EXHIBIT 13.5

                      JERSEY CENTRAL POWER & LIGHT COMPANY

                       2002 ANNUAL REPORT TO STOCKHOLDERS



        Jersey Central Power & Light Company  (JCP&L) is a wholly owned electric
utility operating subsidiary of FirstEnergy Corp. It engages in the distribution
and sale of electric  energy in an area of  approximately  3,300 square miles in
New Jersey.  It also engages in the sale,  purchase and  interchange of electric
energy with other  electric  companies.  The area it serves has a population  of
approximately 2.7 million.

        In August 2000, FirstEnergy entered into an agreement to merge with GPU,
Inc.,  under which  FirstEnergy  would acquire all of the outstanding  shares of
GPU, Inc.'s common stock for approximately  $4.5 billion in cash and FirstEnergy
common  stock.  The merger  became  effective  on  November 7, 2001 and is being
accounted for by the purchase method. Prior to that time, Jersey Central Power &
Light Company was a wholly owned subsidiary of GPU, Inc.






Contents                                                               Page
--------                                                               ----
Selected Financial Data...........................................       1
Management's Discussion and Analysis..............................      2-11
Consolidated Statements of Income.................................      12
Consolidated Balance Sheets.......................................      13
Consolidated Statements of Capitalization.........................      14
Consolidated Statements of Common Stockholder's Equity............      15
Consolidated Statements of Preferred Stock........................      15
Consolidated Statements of Cash Flows.............................      16
Consolidated Statements of Taxes..................................      17
Notes to Consolidated Financial Statements........................     18-30
Reports of Independent Accountants................................     31-32


<PAGE>

<TABLE>

                                          JERSEY CENTRAL POWER & LIGHT COMPANY

                                                 SELECTED FINANCIAL DATA

<CAPTION>
                                                          Nov. 7 -      Jan. 1 -
                                             2002     Dec. 31, 2001  Nov. 6, 2001    2000         1999         1998
----------------------------------------------------------------------------------------------------------------------
                                                                    (Dollars in thousands)

<S>                                       <C>         <C>           <C>           <C>          <C>          <C>
Operating Revenues......................  $2,328,415   $  282,902 | $1,838,638    $1,979,297   $2,018,209   $2,069,648
                                          ==========   ========== | ==========    ==========   ==========   ==========
                                                                  |
Operating Income........................  $  335,209   $   43,666 | $  292,847    $  283,227   $  277,420   $  297,614
                                          ==========   ========== | ==========    ==========   ==========   ==========
                                                                  |
Net Income .............................  $  251,895   $   30,041 | $   34,467    $  210,812   $  172,380   $  222,442
                                          ==========   ========== | ==========    ==========   ==========   ==========
                                                                  |
Earnings on Common Stock................  $  253,359   $   29,343 | $   29,920    $  203,908   $  162,862   $  212,377
                                          ==========   ========== | ==========    ==========   ==========   ==========
                                                                  |
Total Assets............................  $8,052,755   $8,039,998 |               $6,009,054   $5,587,677   $4,382,073
                                          ==========   ========== |               ==========   ==========   ==========
                                                                  |
                                                                  |
Capitalization:                                                   |
   Common Stockholder's Equity..........  $3,274,069   $3,163,701 |               $1,459,260   $1,385,367   $1,557,073
   Preferred Stock-                                               |
     Not Subject to Mandatory Redemption      12,649       12,649 |                   12,649       12,649       37,741
     Subject to Mandatory Redemption....          --       44,868 |                   51,500       73,167       86,500
   Company-Obligated Mandatorily                                  |
     Redeemable Preferred Securities....     125,244      125,250 |                  125,000      125,000      125,000
   Long-Term Debt.......................   1,210,446    1,224,001 |                1,093,987    1,133,760    1,173,532
                                          ----------   ---------- |               ----------   ----------   ----------
     Total Capitalization...............  $4,622,408   $4,570,469 |               $2,742,396   $2,729,943   $2,979,846
                                          ==========   ========== |               ==========   ==========   ==========
                                                                  |
                                                                  |
Capitalization Ratios:                                            |
   Common Stockholder's Equity..........        70.8%        69.2%|                     53.2%        50.7%        52.2%
   Preferred Stock-                                               |
     Not Subject to Mandatory Redemption         0.3          0.3 |                      0.5          0.5          1.3
     Subject to Mandatory Redemption....          --          1.0 |                      1.9          2.7          2.9
   Company-Obligated Mandatorily                                  |
     Redeemable Preferred Securities....         2.7          2.7 |                      4.5          4.6          4.2
   Long-Term Debt.......................        26.2         26.8 |                     39.9         41.5         39.4
                                               -----        ----- |                    -----        -----        -----
     Total Capitalization...............       100.0%       100.0%|                    100.0%       100.0%       100.0%
                                               =====        ===== |                    =====        =====        =====
                                                                  |
                                                                  |
Transmission and Distribution                                     |
Kilowatt-Hour Deliveries (Millions):                              |
   Residential..........................       8,976        1,428 |      7,042         8,087        7,978        7,551
   Commercial...........................       8,509        1,330 |      6,787         7,706        7,624        7,259
   Industrial...........................       3,171          474 |      2,670         3,307        3,289        3,474
   Other................................          81           17 |         66            82           81           81
                                              ------      ------- |     ------        ------       ------       ------
   Total Retail.........................      20,737        3,249 |     16,565        19,182       18,972       18,365
   Total Wholesale......................       5,039          295 |      1,780         2,161        1,622        1,690
                                              ------      ------- |     ------        ------       ------       ------
   Total................................      25,776        3,544 |     18,345        21,343       20,594       20,055
                                              ======      ======= |     ======        ======       ======       ======
                                                                  |
                                                                  |
Customers Served:                                                 |
   Residential..........................     921,716      909,494 |                  896,629      883,930      872,134
   Commercial...........................     112,385      109,985 |                  107,479      107,210      105,611
   Industrial...........................       2,759        2,785 |                    2,835        2,965        3,014
   Other................................       1,393        1,484 |                    1,551        1,648        1,635
                                           ---------    --------- |                ---------      -------      -------
   Total................................   1,038,253    1,023,748 |                1,008,494      995,753      982,394
                                           =========    ========= |                =========      =======      =======

                                                            1

</TABLE>


<PAGE>


                      JERSEY CENTRAL POWER & LIGHT COMPANY


                     Management's Discussion and Analysis of
                  Results of Operations and Financial Condition


        This discussion includes forward-looking statements based on information
currently  available  to  management  that  is  subject  to  certain  risks  and
uncertainties.  Such statements  typically contain,  but are not limited to, the
terms anticipate, potential, expect, believe, estimate and similar words. Actual
results  may  differ  materially  due to  the  speed  and  nature  of  increased
competition  and  deregulation  in the electric  utility  industry,  economic or
weather  conditions  affecting future sales and margins,  changes in markets for
energy  services,  changing  energy market  prices,  legislative  and regulatory
changes (including revised environmental requirements), and the availability and
cost of capital.


Results of Operations

        In 2002,  earnings on common  stock  increased to $253.4  million,  from
$59.3  million in 2001,  due to higher  operating  revenues and the absence of a
2001  after-tax  charge of  $177.5  million,  which  reduced  deferred  costs in
accordance  with  the  Stipulation  of  Settlement  related  to  the  merger  of
FirstEnergy and GPU, Inc.  Partially  offsetting  these  favorable  results were
increased  purchased power costs. In 2001, earnings on common stock decreased by
70.9% to $59.3  million,  from  $203.9  million  in 2000.  Results  in 2001 were
negatively impacted by the $177.5 after-tax charge previously discussed,  and by
higher  purchased  power costs.  Partially  offsetting  these factors were lower
other operating  costs,  and the absence of nuclear  operating costs in 2001, as
well as increases in operating revenues.

        Operating revenues increased $206.9 million in 2002,  following a $142.2
million  increase  in 2001.  The sources of the  changes in  operating  revenues
during  2002 and 2001,  as compared to the prior  year,  are  summarized  in the
following table.

      Sources of Revenue Changes                             2002         2001
      -------------------------------------------------------------------------
             Increase (Decrease)                               (In millions)

      Increase in kilowatt-hour sales due to level of
        retail-customers shopping for generation service... $  34.4     $  67.3
      Increase in other retail kilowatt-hour sales.........    98.2        38.4
      Increase in wholesale sales..........................    74.1        44.1
      All other changes....................................     0.2        (7.6)
      -------------------------------------------------------------------------

      Net Increase in Operating Revenues...................  $206.9      $142.2
      =========================================================================

Electric Sales

        In 2002,  further  reductions  in the number of  customers  who received
their  power from  alternate  suppliers,  and  therefore  returned to us as full
service  customers,  continued to have a positive effect on operating  revenues.
During 2002, only 0.7% of kilowatt-hours  delivered were to shopping  customers,
whereas that  percentage  was 4.5% in 2001 and 11.7% in 2000. In addition to the
higher revenues from returning shopping customers, warmer summer weather in both
2002 and 2001  contributed  to significant  increases in retail sales.  This was
partially offset by a decrease in kilowatt-hour  sales to industrial  customers,
due to a decline in economic conditions during 2002.

        On August 1, 2002,  the  obligation  to provide  power to customers  not
choosing to receive power from an alternative  energy  supplier,  referred to as
Basic  Generation  Service (BGS),  was transferred  from us to external  parties
through  an  auction  process  authorized  by the New  Jersey  Board  of  Public
Utilities (NJBPU).  Therefore,  we began selling all of our self-supplied energy
(non-utility  generation and owned generation) into the wholesale  market.  This
contributed  to a  significant  increase  in  kilowatt-hour  sales to  wholesale
customers  during 2002;  however,  that increase was  partially  offset by lower
average prices for energy in 2002,  compared to 2001. Less  kilowatt-hour  sales
were sold to wholesale  customers in 2001;  however,  revenues  increased due to
higher average prices for energy sold compared to 2000 prices.

                                       2

<PAGE>


        Changes in  kilowatt-hour  sales by customer  class in 2002 and 2001 are
summarized in the following table:


            Changes in Kilowatt-hour Sales  2002         2001
            --------------------------------------------------
               Increase (Decrease)

            Residential..................   7.0%         4.7%
            Commercial...................   3.4%         5.3%
            Industrial...................  (0.7)%       (4.9)%
            --------------------------------------------------

            Total Retail.................   4.3%         3.3%
            Wholesale.................... 142.8%        (4.0)%
            --------------------------------------------------

            Total Sales..................  17.4%         2.6%
            --------------------------------------------------


Operating Expenses and Taxes

        Total  operating  expenses and taxes  increased  $208.2 million in 2002,
after increasing $89.0 million in 2001,  compared to the preceding year. In both
periods,  higher  purchased  power  costs  accounted  for  the  majority  of the
increase.  In 2002, the increase was offset in part by lower general taxes,  due
principally  to a reduction  in the New Jersey  transitional  energy  facilities
assessment during the second quarter of 2002. In 2001, the increase in purchased
power costs was partially  offset by lower other operating costs, due to reduced
bad debt expense and employee  benefit costs,  and decreased  nuclear  operating
costs.  With the sale of the Oyster Creek Nuclear  Generating  Station in August
2000, we no longer have any nuclear operating costs, which were $78.5 million in
2000.  However,  as a result of the sale and higher  customer demand in 2002 and
2001, we have been required to purchase more power.

        In 2002,  fuel and  purchased  power  costs  increased  $179.6  million,
compared to 2001.  The increase was due primarily to more power being  purchased
through  two-party  agreements and from  associated  companies  during 2002. The
increase was partially  offset by a decrease in power purchased  through the PJM
Power Pool,  and the absence of  non-utility  generation  contract  buyout costs
recognized in 2001. Fuel and purchased  power costs increased  $177.6 million in
2001,  compared to 2000.  That  increase  was  primarily  attributed  to greater
quantities of power purchased through both two-party  agreements and through the
PJM Power Pool.  Also  contributing to the increase was a higher average cost of
two-party power  purchases in 2001 than in 2000.  These increases were partially
offset by lower fuel costs due to the sale of Oyster Creek.

Other Income

        Other income increased  $183.3 million in 2002, after decreasing  $199.8
million in 2001,  compared to the prior year. The change in both periods was due
primarily to a 2001 charge of $300 million ($177.5 million net of tax) to reduce
deferred costs in accordance with the  Stipulation of Settlement  related to the
merger between FirstEnergy and GPU.

Net Interest Charges

        In 2002, net interest charges decreased $5.3 million,  compared to 2001,
due primarily to reduced  short-term  borrowing  levels and the  amortization of
fair  value  adjustments   recognized  in  connection  with  the  merger.  These
reductions  were partially  offset by a decrease in deferred  interest costs. In
addition,  we issued $320 million of transition  bonds through a special purpose
finance  subsidiary in 2002 (see Note 4F) and $150 million of notes in 2001, and
redeemed  $192 million of notes in 2002 and $40 million of notes in 2001.  These
transactions  collectively had a minimal net effect on interest charges in 2002.
In 2001,  net interest  charges  decreased  $0.2 million,  compared to the prior
year,  with the slight  decrease due to an increase in deferred  interest costs,
offset by interest expense on the senior notes issued in 2001 and higher average
short-term debt levels.

Preferred Stock Dividend Requirements

        In the third quarter of 2002,  we realized a $3.6 million  non-cash gain
on the  reacquisition  of $29.8  million of  preferred  stock.  Preferred  stock
dividend requirements  decreased $3.1 million in 2002, and $1.7 million in 2001,
compared to the prior year,  due to the 2002  reacquisition  and  redemptions of
cumulative  preferred  stock  pursuant to mandatory  and  optional  sinking fund
provisions during 2002 and 2001.


                                       3
<PAGE>


Capital Resources and Liquidity

     Changes in Cash Position

        As of  December  31,  2002,  we  had  $4.8  million  of  cash  and  cash
equivalents  compared  with $31.4  million as of December  31,  2001.  The major
sources for changes in these balances are summarized below.

     Cash Flows From Operating Activities

        Cash flows provided from operating  activities totaled $309.0 million in
2002 and $289.8 million in 2001. The sources of these changes are as follows:

            Operating Cash Flows                 2002            2001
            ----------------------------------------------------------
                                                     (in millions)
            Cash earnings (1)..................    $325          $219
            Working capital and other..........     (16)           71
            ----------------------------------------------------------

                     Total.....................    $309          $290
            ==========================================================

        (1)  Includes net income, depreciation and  amortization, deferred costs
             recoverable  as  regulatory  assets,  deferred  income  taxes,  and
             and investment tax credits.


     Cash Flows From Financing Activities

        In 2002,  net cash  used for  financing  activities  of  $140.4  million
reflects  redemptions of debt and preferred  stock, as well as $190.7 million in
common  dividend  payments to  FirstEnergy,  offset in part by proceeds from the
issuance of transition bonds. The following table provides details regarding new
issues and redemptions during 2002:

            Securities Issued or Redeemed in 2002
            -------------------------------------------------------------
                                                             (in millions)
            New Issues
                 Transition Bonds (See Note 4)...............     $320
            -------------------------------------------------------------

            Redemptions
                 First Mortgage Bonds........................      192
                 Preferred Stock.............................       52
                 Other.......................................        4
            -------------------------------------------------------------
                     Total Redemptions.......................      248

            Short-term Borrowings, net use of cash...........       18
            -------------------------------------------------------------

        We had no  short-term  indebtedness  on December 31,  2002,  compared to
$18.1  million on December  31,  2001.  We may borrow from our  affiliates  on a
short-term  basis.  We will not issue first  mortgage bonds (FMBs) other than as
collateral for senior notes, since our senior note indentures  prohibit (subject
to certain  exceptions)  us from  issuing any debt which is senior to the senior
notes.  As of December 31, 2002, we had the  capability to issue $393 million of
additional senior notes based upon FMB collateral.  At year-end 2002, based upon
applicable  earnings coverage tests and our charter, we could issue $1.2 billion
of preferred stock (assuming no additional debt was issued).

        At the end of 2002, our common equity as a percentage of  capitalization
stood  at  71%,  as  compared  to 69%  and  53% at the  end of  2001  and  2000,
respectively.  In 2001, we experienced a significant  increase in this ratio due
to the allocation of the purchase price when we were acquired by FirstEnergy.

     Cash Flows From Investing Activities

        In 2002,  cash used in  investing  activities  totaled  $195.2  million,
principally  for property  additions to support the  distribution of electricity
and loans to associated  companies.  In 2001, $167.0 million of cash was used in
investing activities, principally for property additions.

        Our cash  requirements  in 2003  for  operating  expenses,  construction
expenditures,  scheduled debt  maturities and preferred  stock  redemptions  are
expected  to be  met  without  increasing  our  net  debt  and  preferred  stock
outstanding.  Over the next  three  years,  we  expect  to meet our  contractual
obligations  with  cash  from  operations.   Thereafter,  we  expect  to  use  a
combination of cash from operations and funds from the capital markets.

                                       4

<PAGE>


                                  Less than     1-3       3-5      More than
Contractual Obligations  Total     1 Year      Years    Years       5 Years
------------------------------------------------------------------------------
                                             (in millions)
Long-term debt......... $1,374      $174    $   243    $    267    $    690
Preferred stock (1)....    125        --         --          --         125
Operating leases.......     66         3          3           3          57
Purchases (2)..........  4,159       528        943         953       1,735
---------------------------------------------------------------------------
   Total............... $5,724      $705     $1,189      $1,223      $2,607
---------------------------------------------------------------------------

(1) Subject to mandatory redemption
(2) Fuel and power  purchases under  contracts  with fixed or minimum quantities
    and approximate timing


        Our capital  spending for the period 2003 through 2007 is expected to be
about $462 million, of which approximately $102 million applies to 2003.

        Following  approval of the merger of FirstEnergy and GPU by the NJBPU on
September 26, 2001,  Standard and Poor's  adjusted our  corporate  credit rating
from A/A1 to  BBB/A-2,  our senior  secured  debt rating from A+ to BBB+ and our
preferred  stock  rating  from BBB+ to BB+.  The credit  rating  outlook of both
Standard & Poor's and Moody's is stable.

        On February 22, 2002, Moody's Investor Service changed its credit rating
outlook for  FirstEnergy  from stable to  negative.  The change was based upon a
decision by the Commonwealth Court of Pennsylvania to remand to the Pennsylvania
Public  Utility  Commission  (PPUC) for  reconsideration  of its decision on the
mechanism for sharing merger  savings and reversed the PPUC decisions  regarding
rate relief and accounting deferrals rendered in connection with its approval of
the GPU merger.  On April 4, 2002,  Standard & Poor's (S&P)  changed its outlook
for  FirstEnergy's   credit  ratings  from  stable  to  negative  citing  recent
developments  including:  damage to the Davis-Besse reactor vessel head (we have
no ownership  interest in  Davis-Besse),  the  Pennsylvania  Commonwealth  Court
decision,  and  deteriorating  market conditions for some sales of FirstEnergy's
remaining  non-core  assets.  On July 31, 2002, Fitch revised its rating outlook
for  FirstEnergy  securities  to  negative  from  stable.  The  revised  outlook
reflected  the  adverse  impact of the  unplanned  Davis-Besse  outage,  Fitch's
judgment about NRG's financial  ability to consummate the purchase of four power
plants from  FirstEnergy  and Fitch's  expectation of subsequent  delays in debt
reduction.  On August 1, 2002, S&P concluded that while NRG's liquidity position
added  uncertainty to FirstEnergy's  sale of power plants to NRG,  FirstEnergy's
ratings would not be affected.  S&P found its cash flows sufficiently  stable to
support a  continued  (although  delayed)  program of debt and  preferred  stock
redemption.  S&P noted that it would continue to closely monitor our progress on
various  initiatives.  On January 21,  2003,  S&P  indicated  its concern  about
FirstEnergy's  disclosure  of  non-cash  charges  related to  deferred  costs in
Pennsylvania,   pension  and  other   post-retirement   benefits,   and  Emdersa
(FirstEnergy's Argentina operations),  which were higher than anticipated in the
third quarter of 2002.  S&P identified  the restart of the  Davis-Besse  nuclear
plant "...without  significant delay beyond April 2003..." as key to maintaining
its current debt ratings.  S&P also identified other issues it would continue to
monitor  including:  FirstEnergy's  deleveraging  efforts,  free cash  generated
during 2003,  the Jersey  Central  Power & Light  Company rate case,  successful
hedging of our short power position,  and continued  capture of projected merger
savings. While FirstEnergy anticipates being prepared to restart the Davis-Besse
plant in the  spring of 2003,  the  Nuclear  Regulatory  Commission  (NRC)  must
authorize  the unit's  restart  following a formal  inspection  process prior to
FirstEnergy's  returning the unit to service.  Significant delays in the planned
date of  Davis-Besse's  return to service or other  factors  (identified  above)
affecting  the speed with which  FirstEnergy  reduces debt could put  additional
pressure on JCP&L's credit ratings.

Market Risk Information

        We use various market risk sensitive  instruments,  including derivative
contracts,  primarily to manage the risk of price fluctuations.  Our Risk Policy
Committee, comprised of FirstEnergy executive officers, exercises an independent
risk oversight  function to ensure  compliance  with  corporate risk  management
policies and prudent risk management practices.

     Commodity Price Risk

        We  are  exposed  to  market  risk  primarily  due  to  fluctuations  in
electricity and natural gas prices.  To manage the volatility  relating to these
exposures,  we use a  variety  of  non-derivative  and  derivative  instruments,
including forward contracts,  options and futures contracts. The derivatives are
used for hedging purposes.  Most of our non-hedge derivative contracts represent
non-trading positions that do not qualify for hedge treatment under Statement of
Financial  Accounting  Standards  (SFAS)  133.  The  change in the fair value of
commodity  derivative  contracts  related to energy  production  during  2002 is
summarized in the following table:

                                       5

<PAGE>


Increase (Decrease) in the Fair Value of Commodity Derivative Contracts

<TABLE>
<CAPTION>
                                                                Non-Hedge     Hedge    Total
                                                                ---------     -----    -----
                                                                          (In millions)

<S>                                                               <C>         <C>      <C>
Change in the Fair Value of Commodity Derivative Contracts
Outstanding net asset as of January 1, 2002...................... $  1.1      $ 0.4    $1.5
New contract value when entered..................................     --        2.1     2.1
Additions/Change in value of existing contracts..................    7.6       (2.3)    5.3
Settled contracts................................................     --       (0.3)   (0.3)
                                                                  --------------------------

Net Assets - Derivatives Contracts as of December 31, 2002 (1)... $  8.7      $(0.1)   $8.6
                                                                  ==========================

Impact of Changes in Commodity Derivative Contracts (2)
Balance Sheet Effects:
   Other Comprehensive Income (Pre-Tax).......................... $   --      $(2.6)   $2.6)
   Regulatory Liability.......................................... $  7.6      $  --    $7.6

</TABLE>

(1)  Includes $8.6 million in non-hedge commodity derivative contracts which are
     offset by a regulatory liability.
(2)  Represents  the  increase  in  value  of  existing  contracts  and  settled
     contracts.

                                               Non-Hedge    Hedge     Total
                                               ---------    -----     -----
                                                        (In millions)
    Current-
          Other Liabilities...............      $ --        $(0.1)    $(0.1)

    Non-Current-
          Other Deferred Charges..........       8.7           --       8.7
                                                ----         ----     -----

            Net assets....................      $8.7        $(0.1)    $ 8.6
                                                ====        ======    =====

Derivatives included on the Consolidated Balance Sheet as of December 31, 2002:


        The valuation of derivative contracts is based on observable market
information to the extent that such information is available. In cases where
such information is not available, we rely on model-based information. The model
provides estimates of future regional prices for electricity and an estimate of
related price volatility. We use these results to develop estimates of fair
value for financial reporting purposes and for internal management decision
making. Sources of information for the valuation of derivative contracts by year
are summarized in the following table:

Source of Information - Fair Value by Contract Year
---------------------------------------------------

                                       2003  2004  2005  2006  Thereafter  Total
                                       ----  ----  ----  ----  ----------  -----
                                                     (In millions)

Prices based on external sources(1)... $0.2  $0.3  $0.7  $ --    $ --     $1.2
Prices based on models................   --    --    --   1.1     6.3      7.4
                                       ---------------------------------------

    Total(2).......................... $0.2  $0.3  $0.7  $1.1    $6.3     $8.6
                                       =======================================

(1) Broker quote sheets.
(2) Includes $8.6 million from an embedded option that is offset by a regulatory
    liability and does not affect earnings.

        We perform sensitivity analyses to estimate our exposure to the market
risk of our commodity position. A hypothetical 10% adverse shift in quoted
market prices in the near term on derivative instruments would not have had a
material effect on our consolidated financial position or cash flows as of
December 31, 2002.

Interest Rate Risk
------------------

        Our exposure to fluctuations in market interest rates is reduced since
our debt has fixed interest rates, as noted in the following table.

                                       6

<PAGE>


<TABLE>

Comparison of Carrying Value to Fair Value
----------------------------------------------------------------------------------------------------------------
<CAPTION>
                                                                                       There-              Fair
                                 2003       2004       2005       2006       2007       after     Total   Value
----------------------------------------------------------------------------------------------------------------
                                                                (Dollars in millions)
Assets
----------------------------------------------------------------------------------------------------------------
<S>                               <C>         <C>       <C>        <C>         <C>     <C>      <C>       <C>
Investments other than Cash
 and Cash
   Equivalents-Fixed Income....    --          --        --         --          --      $224     $  224   $  224
   Average interest rate.......                                                          5.0%       5.0%
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Liabilities
----------------------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate.....................  $174        $176       $67       $231         $36      $690     $1,374   $1,415
   Average interest rate ......   6.1%        6.9%      6.1%       6.5%        6.1%      7.0%       6.7%
----------------------------------------------------------------------------------------------------------------
Preferred Stock................    --          --        --         --          --      $125     $  125   $  127
   Average dividend rate ......                                                          8.6%       8.6%
----------------------------------------------------------------------------------------------------------------

</TABLE>

        We  are  subject  to  the  inherent   interest  rate  risks  related  to
refinancing maturing debt by issuing new debt securities.  Changes in the market
value of our  nuclear  decommissioning  trust  funds  are  recognized  by making
corresponding changes to the decommissioning  liability,  as described in Note 1
to the consolidated financial statements.

Equity Price Risk
-----------------

        Included  in  nuclear   decommissioning  trusts  are  marketable  equity
securities  carried at their market value of  approximately  $52 million and $65
million at December 31, 2002 and 2001, respectively. A hypothetical 10% decrease
in prices quoted by stock  exchanges  would result in a $5 million  reduction in
fair value as of  December  31,  2002.  (See Note 1 -  "Supplemental  Cash Flows
Information.")

Outlook

        Our industry continues to transition to a more competitive  environment.
Beginning in late 1999,  all of our customers  could select  alternative  energy
suppliers.  We continue  to deliver  power to homes and  businesses  through our
existing  distribution  system,  which remains  regulated.  To support  customer
choice,  rates were  restructured  into unbundled service charges and additional
non-bypassable  charges to recover  stranded  costs  (confirmed by a NJBPU Final
Decision and Order issued in March 2001).  On August 1, 2002,  the obligation to
provide  power  to  those  customers  not  choosing  to  receive  power  from an
alternative  energy  supplier,  referred to as BGS, was  transferred  from us to
external parties through an auction process authorized by the NJBPU.

        Regulatory  assets are costs which  regulatory  agencies have authorized
for recovery from customers in future periods and,  without such  authorization,
would have been charged to income when incurred.  All of our  regulatory  assets
are expected to continue to be recovered  under the provisions of the regulatory
plans as discussed  below.  Our regulatory  assets totaled $3.2 billion and $3.3
billion as of December 31, 2002 and 2001, respectively.

     Regulatory Matters

        Under New  Jersey  transition  legislation,  all  electric  distribution
companies  were  required to file rate cases to determine the level of unbundled
rate  components  to become  effective  August 1, 2003.  On August 1,  2002,  we
submitted two rate filings with the NJBPU. The first filing requested  increases
in base electric rates of approximately $98 million annually.  The second filing
was a request to recover  deferred costs that exceeded  amounts being  recovered
under the current market  transition  charge and societal benefits charge rates;
one  proposed  method of recovery of these  costs is the  securitization  of the
deferred balance as further discussed below. This securitization  methodology is
similar to the Oyster Creek  securitization  discussed below.  Hearings began in
February 2003. The  Administrative  Law Judge's  recommended  decision is due in
June 2003 and the NJBPU's subsequent decision is due in July 2003.

        Our  regulatory  plan  provided for the ability to  securitize  stranded
costs associated with the divested Oyster Creek Nuclear  Generating  Station.  A
February  2002 NJBPU order  authorized  us to issue $320  million of  transition
bonds to  securitize  the recovery of these costs and provided for a usage-based
non-bypassable  transition  bond  charge and for the  transfer  of the  bondable
transition  property to another entity. We sold $320 million of transition bonds
through a wholly owned subsidiary, JCP&L Transition Funding LLC, in June 2002 --
that debt is recognized on the  Consolidated  Balance Sheet (see Note 4). We are
permitted to defer for future collection from customers the amounts by which our
costs of  supplying  BGS to  non-shopping  customers  and costs  incurred  under
non-utility  generation  agreements  exceed  amounts  collected  through BGS and
market  transition  charge  rates.  As of December  31,  2002,  the  accumulated
deferred cost balance totaled approximately $549 million. The NJBPU also allowed
securitization  of our deferred  balance to the extent permitted by law upon our
application  and a  determination  by the NJBPU that the  conditions  of the New
Jersey restructuring legislation are met.

                                       7

<PAGE>

        In December  2001,  the NJBPU  authorized  the auctioning of BGS for the
period from August 1, 2002 through July 31, 2003 to meet the electricity demands
of all customers who have not selected an alternative  supplier.  The results of
the February 2002 auction, with the NJBPU's approval, removed our BGS obligation
of 5,100 MW for the period  August 1, 2002 through  July 31,  2003.  In February
2003, the auctioning of BGS for the period  beginning August 1, 2003 took place.
The auction covered a fixed price bid (applicable to all residential and smaller
commercial and industrial  customers) and an hourly price bid (applicable to all
large  industrial  customers)  process.  We will sell all  self-supplied  energy
(non-utility  generation and owned generation) into the wholesale market,  which
will offset our deferred energy cost balance.

        As part of the restructuring orders, we were obligated, through July 31,
2002,  to  supply  electricity  to  customers  who do not  choose  an  alternate
supplier. The total forecasted peak of this obligation in 2002 was 5,400 MW. The
successful  BGS auction in New Jersey removed that BGS obligation for the period
from August 1, 2002 to July 31, 2003.

     FERC Regulatory Matters

        On December 19, 2002 the Federal  Energy  Regulatory  Commission  (FERC)
granted  unconditional   Regional   Transmission   Organization  status  to  PJM
Interconnection, LLC (PJM). We are a transmission owner in PJM.

     Environmental Matters

        We have been named as a "potentially  responsible  party" (PRP) at waste
disposal sites which may require cleanup under the  Comprehensive  Environmental
Response,  Compensation  and Liability Act of 1980.  Allegations  of disposal of
hazardous  substances at historical  sites and the liability  involved are often
unsubstantiated and subject to dispute;  however,  federal law provides that all
PRPs  for a  particular  site  be held  liable  on a joint  and  several  basis.
Therefore,  potential  environmental  liabilities  have been  recognized  on the
Consolidated  Balance  Sheet as of December 31, 2002,  based on estimates of the
total costs of cleanup, our proportionate  responsibility for such costs and the
financial ability of other nonaffiliated  entities to pay. In addition,  we have
accrued  liabilities for  environmental  remediation of former  manufactured gas
plants in New Jersey;  those costs are being recovered  through a non-bypassable
societal benefits charge. We have accrued liabilities aggregating  approximately
$47.1  million  as of  December  31,  2002.  We  do  not  believe  environmental
remediation  costs  will  have  a  material  adverse  effect  on  our  financial
condition, cash flows or results of operations.

     Legal Matters

        Various lawsuits,  claims and proceedings related to our normal business
operations are pending  against us, the most  significant of which are described
below.

        We have a 25%  ownership  interest  in Unit 2 of the Three  Mile  Island
Nuclear Plant (TMI-2),  which was damaged during a 1979 accident. As a result of
the accident, claims for alleged personal injury against us, Metropolitan Edison
Company,  Pennsylvania  Electric Company and GPU (the defendants) had been filed
in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the
District Court granted a motion for summary judgment filed by the defendants and
dismissed  the ten initial  "test cases" which had been selected for a test case
trial.  In January  2002,  the  District  Court  granted  our motion for summary
judgment on the remaining 2,100 pending claims. In February 2002, the plaintiffs
filed  a  notice  of  appeal  of  this  decision  (see  Note  6  -  Other  Legal
Proceedings).  In  December  2002,  the Court of Appeals  for the Third  Circuit
refused to hear the appeal  which  effectively  ended  further  legal action for
those claims.

        In July 1999, the  Mid-Atlantic  states  experienced a severe heat storm
which  resulted in power  outages  throughout  the service  territories  of many
electric utilities,  including JCP&L. In an investigation into the causes of the
outages and the reliability of the transmission and distribution  systems of all
four New Jersey  electric  utilities,  the NJBPU  concluded that there was not a
prima facie case demonstrating that, overall, we provided unsafe,  inadequate or
improper  service to our  customers.  In July 1999,  two class  action  lawsuits
(subsequently  consolidated  into a single  proceeding) were filed in New Jersey
Superior Court against JCP&L and other GPU companies,  seeking  compensatory and
punitive damages arising from the July 1999 service interruptions in our service
territory.  In May 2001, the court denied  without  prejudice our motion seeking
decertification  of the class.  Discovery  continues in the class action, but no
trial  date has been set.  In  October  2001,  the court  held  argument  on the
plaintiffs'  motion for partial  summary  judgment,  which  contends that we are
bound to several findings of the NJBPU investigation. The plaintiffs' motion was
denied  by the  Court in  November  2001 and the  plaintiffs'  motion to file an
appeal of this decision was denied by the New Jersey Appellate Division. We have
also filed a motion for  partial  summary  judgment  that is  currently  pending
before  the  Superior  Court.  We are  unable to  predict  the  outcome of these
matters.

                                       8

<PAGE>


Significant Accounting Policies

        We prepare our  consolidated  financial  statements in  accordance  with
accounting  principles  that  are  generally  accepted  in  the  United  States.
Application  of these  principles  often  requires  a high  degree of  judgment,
estimates and assumptions that affect financial  results.  All of our assets are
subject to their own specific risks and uncertainties and are regularly reviewed
for  impairment.  Assets related to the  application  of the policies  discussed
below are similarly reviewed with their risks and uncertainties reflecting these
specific factors. Our more significant accounting policies are described below.

     Purchase Accounting

        On  November  7, 2001,  the merger  between  FirstEnergy  and GPU became
effective,  and we became a wholly owned  subsidiary of FirstEnergy.  The merger
was accounted for by the purchase method of accounting,  which requires judgment
regarding the  allocation of the purchase  price based on the fair values of the
assets acquired (including  intangible assets) and the liabilities  assumed. The
fair values of the acquired assets and assumed  liabilities were based primarily
on estimates.  The adjustments reflected in our records, which were finalized in
the fourth  quarter of 2002,  primarily  consist of: (1)  revaluation of certain
property,  plant  and  equipment;  (2)  adjusting  preferred  stock  subject  to
mandatory redemption and long-term debt to estimated fair value; (3) recognizing
additional  obligations  related to  retirement  benefits;  and (4)  recognizing
estimated  severance  and  other  compensation  liabilities.  The  excess of the
purchase  price  over the  estimated  fair  values of the  assets  acquired  and
liabilities  assumed was recognized as goodwill.  Based on the guidance provided
by SFAS 142,  "Goodwill and Other  Intangible  Assets," we evaluate our goodwill
for  impairment  at least  annually  and  would  make  such an  evaluation  more
frequently if indicators of impairment  should arise.  The forecasts used in our
evaluations of goodwill reflect operations  consistent with our general business
assumptions. Unanticipated changes in those assumptions could have a significant
effect on our future  evaluations  of goodwill.  As of December 31, 2002, we had
recorded goodwill of approximately $2.0 billion related to the merger.

     Regulatory Accounting

        We are  subject  to  regulation  that  sets the  prices  (rates)  we are
permitted to charge our customers  based on costs that the  regulatory  agencies
determine we are permitted to recover.  At times,  regulators  permit the future
recovery through rates of costs that would be currently charged to expense by an
unregulated  company.  This  rate-making  process  results in the  recording  of
regulatory assets based on anticipated  future cash inflows.  As a result of the
changing regulatory  framework in New Jersey, a significant amount of regulatory
assets have been  recorded - $3.2 billion as of December 31, 2002.  We regularly
review these assets to assess their ultimate  recoverability within the approved
regulatory  guidelines.  Impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.

     Derivative Accounting

        Determination  of appropriate  accounting  for  derivative  transactions
requires the involvement of management representing operations, finance and risk
assessment.  In order to determine the  appropriate  accounting  for  derivative
transactions,  the  provisions of the contract need to be carefully  assessed in
accordance  with  the  authoritative   accounting  literature  and  management's
intended use of the derivative.  New authoritative  guidance  continues to shape
the  application  of  derivative  accounting.   Management's   expectations  and
intentions  are key factors in  determining  the  appropriate  accounting  for a
derivative  transaction and, as a result,  such  expectations and intentions are
documented. Derivative contracts that are determined to fall within the scope of
SFAS 133, as amended, must be recorded at their fair value. Active market prices
are not always  available  to  determine  the fair value of the later years of a
contract,  requiring  that various  assumptions  and  estimates be used in their
valuation.  We continually monitor our derivative  contracts to determine if our
activities, expectations, intentions, assumptions and estimates remain valid. As
part of our normal operations,  we enter into commodity contracts which increase
the impact of derivative accounting judgments.

     Revenue Recognition

        We follow the accrual  method of accounting  for  revenues,  recognizing
revenue for  kilowatt-hours  that have been delivered but not yet billed through
the  end of the  accounting  period.  The  determination  of  unbilled  revenues
requires management to make various estimates including:

        o  Net energy generated or purchased for retail load
        o  Losses of energy over transmission and distribution lines
        o  Mix of kilowatt-hour usage by residential,  commercial and industrial
           customers
        o  Kilowatt-hour  usage  of   customers   receiving   electricity   from
           alternative suppliers

                                       9

<PAGE>


     Pension and Other Postretirement Benefits Accounting

        Our  reported  costs  of  providing   non-contributory  defined  pension
benefits and  postemployment  benefits other than pensions  (OPEB) are dependent
upon  numerous  factors  resulting  from  actual  plan  experience  and  certain
assumptions.

        Pension and OPEB costs are affected by employee demographics  (including
age, compensation levels, and employment periods), the level of contributions we
make to the plans, and earnings on plan assets.  Pension and OPEB costs may also
be affected by changes to key assumptions, including anticipated rates of return
on plan  assets,  the  discount  rates  and  health  care  trend  rates  used in
determining the projected benefit obligations and pension and OPEB costs.

        In accordance  with SFAS 87,  "Employers'  Accounting  for Pensions" and
SFAS  106,  "Employers'  Accounting  for  Postretirement   Benefits  Other  Than
Pensions," changes in pension and OPEB obligations associated with these factors
may  not be  immediately  recognized  as  costs  on the  income  statement,  but
generally  are  recognized in future years over the  remaining  average  service
period of plan  participants.  SFAS 87 and SFAS 106 delay recognition of changes
due to the  long-term  nature of pension  and OPEB  obligations  and the varying
market  conditions  likely  to  occur  over  long  periods  of  time.  As  such,
significant  portions of pension  and OPEB costs  recorded in any period may not
reflect the actual level of cash benefits  provided to plan participants and are
significantly  influenced by assumptions about future market conditions and plan
participants' experience.

        In selecting an assumed discount rate, we consider  currently  available
rates  of  return  on  high-quality  fixed  income  investments  expected  to be
available during the period to maturity of the pension and other  postretirement
benefit obligations. Due to the significant decline in corporate bond yields and
interest rates in general  during 2002, we reduced the assumed  discount rate as
of December 31, 2002 to 6.75% from 7.25% used in 2001.

        Our assumed rate of return on pension plan assets  considers  historical
market returns and economic  forecasts for the types of investments  held by our
pension  trusts.  The market values of our pension  assets have been affected by
sharp declines in the equity markets since  mid-2000.  In 2002, plan assets have
earned (11.3)%.  Our pension costs in 2002 were computed  assuming a 10.25% rate
of return on plan  assets.  As of December  31, 2002 the assumed  return on plan
assets was  reduced to 9.00%  based upon our  projection  of future  returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.

        Based on pension  assumptions and pension plan assets as of December 31,
2002, we will not be required to fund our pension plans in 2003. While OPEB plan
assets have also been  affected  by sharp  declines  in the equity  market,  the
impact  is not as  significant  due to the  relative  size of the  plan  assets.
However,  health care cost trends have  significantly  increased and will affect
future OPEB costs.  The 2003  composite  health  care trend rate  assumption  is
approximately 10%-12% gradually decreasing to 5% in later years, compared to our
2002 assumption of approximately 10% in 2002,  gradually  decreasing to 4%-6% in
later years. In determining our trend rate assumptions, we included the specific
provisions of our health care plans, the  demographics and utilization  rates of
plan participants,  actual cost increases  experienced in our health care plans,
and projections of future medical trend rates. Our non-cash, pre-tax pension and
OPEB  expense  under SFAS 87 and SFAS 106 is expected to increase by $29 million
and $10  million,  respectively  - a total of $39 million in 2003 as compared to
2002.

 Increase in Costs from Adverse Changes in Key Assumptions
-----------------------------------------------------------------------------
 Assumption                     Adverse Change     Pension     OPEB     Total
-----------------------------------------------------------------------------
                                               (In millions)
 Discount rate................  Decrease by 0.25%    $2.5      $1.3     $3.8
 Long-term return on assets...  Decrease by 0.25%    $1.7      $0.5     $2.2
 Health care trend rate.......  Increase by 1%       na        $3.7     $3.7

     Long-Lived Assets

        In accordance with SFAS 144,  "Accounting for the Impairment or Disposal
of  Long-Lived  Assets,"  we  periodically  evaluate  our  long-lived  assets to
determine  whether  conditions exist that would indicate that the carrying value
of an asset may not be fully recoverable.  The accounting standard requires that
if the sum of future cash flows (undiscounted)  expected to result from an asset
is less  than the  carrying  value of the  asset,  an asset  impairment  must be
recognized in the financial statements.  If impairment were to occur, other than
of a temporary  nature, we would recognize a loss - calculated as the difference
between the carrying value and the estimated fair value of the asset (discounted
future net cash flows).

                                       10

<PAGE>


Recently Issued Accounting Standards Not Yet Implemented
--------------------------------------------------------

     SFAS 143, "Accounting for Asset Retirement Obligations"

        In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations".  The new statement  provides  accounting  standards for retirement
obligations  associated with tangible  long-lived assets, with adoption required
by January 1, 2003.  SFAS 143 requires that the fair value of a liability for an
asset  retirement  obligation be recorded in the period in which it is incurred.
The associated  asset  retirement  costs are capitalized as part of the carrying
amount of the long-lived  asset. Over time the capitalized costs are depreciated
and the present value of the asset retirement liability increases,  resulting in
a period  expense.  However,  rate-regulated  entities may recognize  regulatory
assets  or  liabilities  if the  criteria  for  such  treatment  are  met.  Upon
retirement,  a gain or  loss  would  be  recorded  if the  cost  to  settle  the
retirement obligation differs from the carrying amount.

        We have identified applicable legal obligations as defined under the new
standard, principally for nuclear power plant decommissioning.  Upon adoption of
SFAS 143 in January 2003, asset retirement costs of $98 million were recorded as
part  of the  carrying  amount  of  the  related  long-lived  asset,  offset  by
accumulated  depreciation of $98 million.  The asset retirement liability at the
date of adoption was $104  million.  As of December  31,  2002,  we had recorded
decommissioning  liabilities  of  $130  million.  The  change  in the  estimated
liabilities  resulted  from  changes in  methodology  and  various  assumptions,
including changes in the projected dates for decommissioning.

        Management expects that substantially all of our nuclear decommissioning
costs will be recoverable  through regulated rates.  Therefore,  we recognized a
regulatory liability of $26 million upon adoption of SFAS 143 for the transition
amounts related to  establishing  the asset  retirement  obligations for nuclear
decommissioning.

        SFAS  146,  "Accounting  for  Costs  Associated  with  Exit or  Disposal
        Activities"

        This statement,  which was issued by the FASB in July 2002, requires the
recognition  of costs  associated  with exit or disposal  activities at the time
they are  incurred  rather  than when  management  commits  to a plan of exit or
disposal.  It also  requires the use of fair value for the  measurement  of such
liabilities.  The new standard  supersedes  guidance provided by Emerging Issues
Task  Force  Issue  No.  94-3,  "Liability   Recognition  for  Certain  Employee
Termination  Benefits  and Other  Costs to Exit an Activity  (including  Certain
Costs  Incurred in a  Restructuring)."  This new standard was effective for exit
and disposal  activities  initiated after December 31, 2002. Since it is applied
prospectively,  there will be no impact upon adoption.  However,  SFAS 146 could
change the timing and amount of costs  recognized in connection with future exit
or disposal activities.

        FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure
        Requirements   for   Guarantees,   Including   Indirect   Guarantees  of
        Indebtedness of Others - an interpretation of FASB Statements No. 5, 57,
        and 107 and rescission of FASB Interpretation No. 34"

        The FASB issued FIN 45 in January 2003. This  interpretation  identifies
minimum guarantee  disclosures required for annual periods ending after December
15, 2002. It also clarifies  that  providers of guarantees  must record the fair
value of those  guarantees  at their  inception.  This  accounting  guidance  is
applicable  on a  prospective  basis to  guarantees  issued  or  modified  after
December  31,  2002.  We do not believe  that  implementation  of FIN 45 will be
material but we will continue to evaluate anticipated guarantees.

        FIN 46, "Consolidation of Variable Interest Entities - an interpretation
        of ARB 51"

        In January  2003,  the FASB  issued this  interpretation  of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities  in  which  equity  investors  do not  have  the  characteristics  of a
controlling  financial interest or do not have sufficient equity at risk for the
entity to finance  its  activities  without  additional  subordinated  financial
support  from other  parties.  This  Interpretation  requires an  enterprise  to
disclose  the  nature  of its  involvement  with a VIE if the  enterprise  has a
significant  variable  interest  in  the  VIE  and to  consolidate  a VIE if the
enterprise is the primary  beneficiary.  VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this  interpretation's  provisions  in the first  interim or
annual  reporting  period  beginning  after June 15, 2003 (our third  quarter of
2003).  The FASB also  identified  transitional  disclosure  provisions  for all
financial statements issued after January 31, 2003.

        We currently have transactions with entities in connection with the sale
of preferred  securities  and debt secured by bondable  property,  and which are
reasonably  possible  of meeting  within the scope of this  interpretation,  and
which may meet the  definition of a VIE in accordance  with FIN 46. We currently
consolidate those entities and believe we will continue to consolidate following
the adoption of FIN 46.

                                       11

<PAGE>


<TABLE>

                                        JERSEY CENTRAL POWER & LIGHT COMPANY

                                         CONSOLIDATED STATEMENTS OF INCOME

<CAPTION>
                                                                                 Nov 7 -       Jan. 1 -
                                                                  2002       Dec. 31, 2001   Nov. 6, 2001     2000
----------------------------------------------------------------------------------------------------------------------
                                                                                  (In thousands)

<S>                                                            <C>              <C>           <C>          <C>
OPERATING REVENUES........................................     $2,328,415       $282,902   |  $1,838,638   $1,979,297
                                                               ----------       --------   |  ----------   ----------
                                                                                           |
OPERATING EXPENSES AND TAXES:                                                              |
   Fuel and purchased power...............................      1,248,012        136,123   |     932,300      890,812
   Nuclear operating costs................................             --             --   |          --       78,487
   Other operating costs..................................        272,890         40,670   |     237,513      303,353
                                                               ----------       --------   |  ----------   ----------
     Total operation and maintenance expenses.............      1,520,902        176,793   |   1,169,813    1,272,652
   Provision for depreciation and amortization............        244,759         35,124   |     205,918      235,001
   General taxes..........................................         56,049          8,919   |      56,582       64,398
   Income taxes...........................................        171,496         18,400   |     113,478      124,019
                                                               ----------       --------   |  ----------   ----------
     Total operating expenses and taxes...................      1,993,206        239,236   |   1,545,791    1,696,070
                                                               ----------       --------   |  ----------   ----------
                                                                                           |
OPERATING INCOME..........................................        335,209         43,666   |     292,847      283,227
                                                                                           |
OTHER INCOME (EXPENSE)....................................          7,653          1,186   |    (176,875)      24,146
                                                               ----------       --------   |  ----------   -----------
                                                                                           |
INCOME BEFORE NET INTEREST CHARGES........................        342,862         44,852   |     115,972      307,373
                                                               ----------       --------   |  ----------   ----------
                                                                                           |
NET INTEREST CHARGES:                                                                      |
   Interest on long-term debt.............................         92,314         14,234   |      77,205       85,220
   Allowance for borrowed funds used during                                                |
     construction.........................................           (583)           135   |      (1,665)      (1,287)
   Deferred interest .....................................         (8,815)        (2,243)  |     (12,557)      (7,951)
   Other interest expense.................................         (2,643)         1,080   |       9,427        9,879
   Subsidiary's preferred stock dividend requirements.....         10,694          1,605   |       9,095       10,700
                                                               ----------       --------      ----------   ----------
     Net interest charges.................................         90,967         14,811   |      81,505       96,561
                                                               ----------       --------   |  ----------   ----------
                                                                                           |
NET INCOME................................................        251,895         30,041   |      34,467      210,812
                                                                                           |
PREFERRED STOCK DIVIDEND REQUIREMENTS.....................          2,125            698   |       4,547        6,904
                                                                                           |
GAIN ON PREFERRED STOCK REACQUISITION.....................         (3,589)            --   |          --           --
                                                               ----------       ---------  |  ----------   ----------
                                                                                           |
EARNINGS ON COMMON STOCK..................................     $  253,359       $ 29,343   |  $   29,920   $  203,908
                                                               ==========       ========   |  ==========   ==========


        The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

                                                           12

</TABLE>

<PAGE>

<TABLE>

                                       JERSEY CENTRAL POWER & LIGHT COMPANY

                                             CONSOLIDATED BALANCE SHEETS

<CAPTION>
As of December 31,                                                                        2002             2001
------------------------------------------------------------------------------------------------------------------
                                                                                              (In thousands)
                                         ASSETS
UTILITY PLANT:
<S>                                                                                    <C>              <C>
   In service.....................................................................     $3,478,803       $3,431,823
   Less-Accumulated provision for depreciation....................................      1,343,846        1,313,259
                                                                                       ----------       ----------
                                                                                        2,134,957        2,118,564
   Construction work in progress-
     Electric plant...............................................................         20,687           60,482
                                                                                       ----------       ----------
                                                                                        2,155,644        2,179,046
OTHER PROPERTY AND INVESTMENTS:
   Nuclear plant decommissioning trusts...........................................        106,820          114,899
   Nuclear fuel disposal trust....................................................        149,738          137,098
   Long-term notes receivable from associated companies...........................         20,333           20,333
   Other..........................................................................         18,202            6,643
                                                                                       ----------       ----------
                                                                                          295,093          278,973
                                                                                       ----------       ----------
CURRENT ASSETS:
   Cash and cash equivalents......................................................          4,823           31,424
   Receivables-
     Customers (less accumulated provisions of $4,509,000 and $12,923,000
       respectively, for uncollectible accounts)..................................        247,624          226,392
     Associated companies.........................................................            318            6,412
     Other........................................................................         20,134           20,729
   Notes receivable from associated companies.....................................         77,358               --
   Materials and supplies, at average cost........................................          1,341            1,348
   Prepayments and other..........................................................         37,719           16,569
                                                                                       ----------       ----------
                                                                                          389,317          302,874
                                                                                       ----------       ----------
DEFERRED CHARGES:
   Regulatory assets..............................................................      3,199,012        3,324,804
   Goodwill.......................................................................      2,000,875        1,926,526
   Other..........................................................................         12,814           27,775
                                                                                       ----------       ----------
                                                                                        5,212,701        5,279,105
                                                                                       $8,052,755       $8,039,998
                           CAPITALIZATION AND LIABILITIES

CAPITALIZATION (See Consolidated Statements of Capitalization):
   Common stockholder's equity....................................................     $3,274,069       $3,163,701
   Preferred stock-
     Not subject to mandatory redemption..........................................         12,649           12,649
     Subject to mandatory redemption..............................................             --           44,868
   Company-obligated mandatorily redeemable preferred securities..................        125,244          125,250
   Long-term debt.................................................................      1,210,446        1,224,001
                                                                                       ----------       ----------
                                                                                        4,622,408        4,570,469
CURRENT LIABILITIES:
   Currently payable long-term debt and preferred stock...........................        173,815           60,848
   Short-term borrowings (Note 5)-
     Associated companies.........................................................             --           18,149
   Accounts payable-
     Associated companies.........................................................        170,803          171,168
     Other........................................................................        106,504           89,739
   Accrued  taxes.................................................................         13,844           35,783
   Accrued interest...............................................................         27,161           25,536
   Other..........................................................................        112,408           79,589
                                                                                       ----------       ----------
                                                                                          604,535          480,812
                                                                                       ----------       ----------
DEFERRED CREDITS:
   Accumulated deferred income taxes..............................................        691,721          514,216
   Accumulated deferred investment tax credits....................................          9,939           13,490
   Power purchase contract loss liability ........................................      1,710,968        1,968,823
   Nuclear fuel disposal costs....................................................        166,191          163,377
   Nuclear plant decommissioning costs............................................        135,355          137,424
   Other..........................................................................        111,638          191,387
                                                                                       ----------       ----------
                                                                                        2,825,812        2,988,717
COMMITMENTS AND CONTINGENCIES
  (Notes 3 and 6).................................................................     ----------       ----------

                                                                                       $8,052,755       $8,039,998
                                                                                       ==========       ==========

       The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

                                                           13

</TABLE>

<PAGE>

<TABLE>

                                       JERSEY CENTRAL POWER & LIGHT COMPANY

                                     CONSOLIDATED STATEMENTS OF CAPITALIZATION
<CAPTION>
As of December 31,                                                                            2002        2001
----------------------------------------------------------------------------------------------------------------
                               (Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
<S>                                                                                     <C>              <C>
   Common stock, par value $10 per share, authorized 16,000,000 shares
     15,371,270 shares outstanding....................................................  $    153,713     $  153,713
   Other paid-in capital..............................................................     3,029,218      2,981,117
   Accumulated other comprehensive loss (Note 4E).....................................          (865)          (472)
   Retained earnings (Note 4A)........................................................        92,003         29,343
                                                                                        ------------     ----------
     Total common stockholder's equity................................................     3,274,069      3,163,701
                                                                                        ------------     ----------
<CAPTION>
                                               Number of Shares           Optional
                                                  Outstanding          Redemption Price
                                               ----------------      --------------------
                                               2002        2001      Per Share  Aggregate
                                               ----        ----      ---------  ---------
PREFERRED STOCK (Note 4B):
Cumulative, without par value-
Authorized 125,000 shares
   Not Subject to Mandatory Redemption:
<S>                                           <C>         <C>         <C>        <C>          <C>           <C>
       4% Series........................      125,000     125,000     $106.50    $13,313      12,649        12,649

   Subject to Mandatory Redemption:
     8.65% Series J.....................           --     250,001      101.30    $25,325          --        26,750
     7.52% Series K.....................           --     265,000      103.76     27,496          --        28,951
     Redemption Within One Year.........                       --                  --             --       (10,833)
                                              -------     -------      ------    -------      ------       --------
       Total Subject to Mandatory
         Redemption.....................           --     515,001                $52,821          --        44,868
                                              =======     =======                =======      ------       -------

<CAPTION>
COMPANY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY LIMITED
PARTNERSHIP HOLDING SOLELY COMPANY
SUBORDINATED DEBENTURES (NOTE 4C):
   Cumulative, $25 par value -
   Authorized 5,000,000 shares
     Subject to Mandatory Redemption:
   <S>                                                                                    <C>           <C>

       8.56% due 2044..................................................................      125,244       125,250

LONG-TERM DEBT (Note 4D):
   First mortgage bonds:
     9.000% due 2002...................................................................           --        50,000
     6.375% due 2003...................................................................      150,000       150,000
     7.125% due 2004...................................................................      160,000       160,000
     6.780% due 2005...................................................................       50,000        50,000
     6.850% due 2006...................................................................       40,000        40,000
     8.250% due 2006...................................................................       23,053        50,000
     7.900% due 2007...................................................................       18,361        40,000
     7.125% due 2009...................................................................        6,300         6,300
     7.100% due 2015...................................................................       12,200        12,200
     9.200% due 2021...................................................................       22,963        50,000
     8.320% due 2022...................................................................       40,000        40,000
     8.550% due 2022...................................................................       13,623        30,000
     8.820% due 2022...................................................................           --        12,000
     8.850% due 2022...................................................................           --        38,000
     7.980% due 2023...................................................................       40,000        40,000
     7.500% due 2023...................................................................      125,000       125,000
     8.450% due 2025...................................................................       50,000        50,000
     6.750% due 2025...................................................................      150,000       150,000
                                                                                          ----------    ----------
       Total first mortgage bonds......................................................      901,500     1,093,500
                                                                                          ----------    ----------

   Secured notes:
     6.450% due 2006...................................................................      150,000       150,000
     4.190% due 2007...................................................................       91,111            --
     5.390% due 2010...................................................................       52,297            --
     5.810% due 2013...................................................................       77,075            --
     6.160% due 2017...................................................................       99,517            --
                                                                                          ----------    ----------
       Total secured notes.............................................................      470,000       150,000
                                                                                          ----------    ----------
   Unsecured notes:
     7.69% due 2039....................................................................        2,984         2,998
                                                                                          ----------    -----------

   Net unamortized premium on debt.....................................................        9,777       27,518
                                                                                          ----------    ----------
   Long-term debt due within one year..................................................     (173,815)      (50,015)
                                                                                          ----------    -----------
       Total long-term debt............................................................    1,210,446     1,224,001
                                                                                          ----------    ----------

TOTAL CAPITALIZATION...................................................................   $4,622,408    $4,570,469
                                                                                          ==========    ==========

         The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

                                                           14

</TABLE>

<PAGE>

<TABLE>

                                          JERSEY CENTRAL POWER & LIGHT COMPANY

                                 CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

<CAPTION>
                                                                                              Accumulated
                                                                  Common Stock       Other      Other
                                               Comprehensive    Number     Par      Paid-In   Comprehensive  Retained
                                                   Income      of Shares  Value     Capital   Income (Loss)  Earnings
                                               -------------   ---------  -----     -------   -------------  --------
                                                                        (Dollars in thousands)
<S>                                                 <C>      <C>         <C>       <C>           <C>       <C>
Balance, January 1, 2000.......................              15,371,270  $153,713  $ 510,769     $    7    $ 720,878
   Net income..................................     $210,812                                                 210,812
   Minimum pension liability...................          (15)                                       (15)
                                                    --------
   Comprehensive income........................      210,797
                                                    --------
   Cash dividends on preferred stock...........                                                               (6,904)
   Cash dividends on common stock..............                                                             (130,000)
--------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000.....................              15,371,270   153,713    510,769         (8)     794,786
   Net income..................................       34,467                                                  34,467
   Net unrealized gain on investments..........            2                                          2
   Net unrealized gain on derivative
     instruments...............................          768                                        768
                                                    --------
   Comprehensive income........................       35,237
                                                    --------
   Cash dividends on preferred stock...........                                                               (4,547)
   Cash dividends on common stock  ............                                                             (175,000)
--------------------------------------------------------------------------------------------------------------------
Balance, November 6, 2001......................              15,371,270   153,713    510,769        762      649,706
   Purchase accounting fair value adjustment...                                    2,470,348       (762)    (649,706)
--------------------------------------------------------------------------------------------------------------------
Balance, November 7, 2001......................              15,371,270   153,713  2,981,117         --           --
   Net income..................................       30,041                                                  30,041
   Net unrealized gain (loss) on derivative
     instruments...............................         (472)                                      (472)
                                                    --------
   Comprehensive income........................       29,569
                                                    --------
   Cash dividends on preferred stock...........                                                                 (698)
---------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001.....................              15,371,270   153,713  2,981,117       (472)      29,343
   Net income..................................      251,895                                                 251,895
   Net unrealized gain (loss) on derivative
     instruments...............................         (393)                                      (393)
                                                    --------
   Comprehensive income........................     $251,502
                                                    --------
   Cash dividends on preferred stock...........                                                                1,465
   Cash dividends on common stock..............                                                             (190,700)
   Purchase accounting fair value adjustment  .                                       48,101
--------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002.....................              15,371,270  $153,713 $3,029,218     $ (865)   $  92,003
====================================================================================================================



<CAPTION>
                                    CONSOLIDATED STATEMENTS OF PREFERRED STOCK

                                                          Not Subject to              Subject to
                                                      Mandatory Redemption       Mandatory Redemption
                                                      --------------------       ---------------------
                                                       Number     Carrying       Number      Carrying
                                                      of Shares     Value        of Shares     Value
                                                      ---------   --------       ---------   --------
                                                                 (Dollars in thousands)

             <S>                                       <C>        <C>            <C>         <C>
             Balance, January 1, 2000............      125,000    $12,649        5,840,000   $209,000
               Redemptions-
                 7.52% Series....................                                  (50,000)    (5,000)
                 8.65% Series....................                              (   166,666)   (16,667)
             -----------------------------------------------------------------------------------------
             Balance, December 31, 2000..........      125,000     12,649        5,623,334    187,333
               Redemptions-
                 7.52% Series....................                                  (25,000)    (2,500)
                 8.65% Series....................                                  (83,333)    (8,333)
                 Purchase accounting fair
                    value adjustment.............                                               4,451
             -----------------------------------------------------------------------------------------
             Balance, December 31, 2001..........      125,000     12,649        5,515,001    180,951
               Redemptions-
                 7.52% Series....................                                 (265,000)   (28,951)
                 8.65% Series....................                                 (250,001)   (26,750)
                 Purchase accounting fair
                    value adjustment.............                                                  (6)
             -----------------------------------------------------------------------------------------
             Balance, December 31, 2002..........      125,000    $12,649        5,000,000   $125,244
             =========================================================================================


         The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

</TABLE>
                                                           15
<PAGE>

<TABLE>

                                          JERSEY CENTRAL POWER & LIGHT COMPANY

                                          CONSOLIDATED STATEMENTS OF CASH FLOWS

<CAPTION>
                                                                                   Nov. 7 -      Jan. 1 -
                                                                       2002     Dec. 31, 2001  Nov. 6, 2001    2000
-----------------------------------------------------------------------------------------------------------------------
                                                                                      (In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
<S>                                                                 <C>           <C>          <C>         <C>
Net Income........................................................  $ 251,895     $ 30,041   | $  34,467   $ 210,812
   Adjustments to reconcile net income to net                                                |
   cash from operating activities:                                                           |
     Provision for depreciation and amortization..................    244,759       35,124   |   205,918     235,001
     Nuclear fuel and lease amortization..........................         --           --   |        --      11,472
     Other amortization...........................................        849        1,360   |    23,025      34,563
     Deferred costs recoverable as regulatory assets..............   (285,065)     (25,471)  |   (29,312)   (229,321)
     Deferred income taxes, net...................................    115,866        5,609   |   (58,132)    270,479
     Investment tax credits, net..................................     (3,551)        (540)  |    (3,057)    (15,027)
     Receivables..................................................    (14,542)       7,050   |    27,177      11,766
     Materials and supplies.......................................          7            2   |      (842)       (268)
     Accounts payable.............................................     16,399       (5,060)  |   (44,498)     51,633
     Other (Note 7)...............................................    (17,642)      20,563   |    66,328    (230,100)
                                                                    ---------     --------   | ---------   ---------
       Net cash provided from operating activities................    308,975       68,678   |   221,074     351,010
                                                                    ---------     --------   | ---------   ---------
                                                                                             |
CASH FLOWS FROM FINANCING ACTIVITIES:                                                        |
  New Financing-                                                                             |
     Long-term debt...............................................    318,106           --   |   148,796          --
     Short-term borrowings, net...................................         --           --   |        --      29,200
   Redemptions and Repayments-                                                               |
     Preferred stock..............................................    (51,500)          --   |   (10,833)    (21,667)
     Long-term debt...............................................   (196,033)     (40,000)  |        --     (40,000)
     Short-term borrowings, net...................................    (18,149)      (1,851)  |    (9,200)         --
     Capital lease payments.......................................         --           --   |        --     (48,516)
   Dividend Payments-                                                                        |
     Common stock.................................................   (190,700)          --   |  (175,000)   (130,000)
     Preferred stock..............................................     (2,125)        (698)  |    (4,547)     (7,065)
                                                                    ---------     --------   | ---------   ----------
       Net cash used for financing activities.....................   (140,401)     (42,549)  |   (50,784)   (218,048)
                                                                    ---------     --------   | ----------  ----------
                                                                                             |
CASH FLOWS FROM INVESTING ACTIVITIES:                                                        |
   Property additions.............................................    (97,346)     (21,487)  |  (141,030)   (144,389)
   Contributions to decommissioning trusts........................         --         (202)  |    (1,004)   (130,444)
   Sale of investments............................................         --           --   |        --      74,797
   Loans to associated companies..................................    (77,358)          --   |        --          --
   Other..........................................................    (20,471)      (1,078)  |    (2,215)       (624)
                                                                    ---------     --------   | ----------- ---------
       Net cash used for investing activities.....................   (195,175)     (22,767)  |  (144,249)   (200,660)
                                                                    ---------     --------   | ---------   ----------
                                                                                             |
                                                                                             |
Net increase (decrease) in cash and cash equivalents..............    (26,601)       3,362   |    26,041     (67,698
Cash and cash equivalents at beginning of period..................     31,424       28,062   |     2,021      69,719
                                                                    ---------     --------   | ---------   ---------
Cash and cash equivalents at end of period........................  $   4,823     $ 31,424   | $  28,062   $   2,021
                                                                    =========     ========   | =========   =========
                                                                                             |
SUPPLEMENTAL CASH FLOWS INFORMATION:                                                         |
Cash Paid During the Year-                                                                   |
     Interest (net of amounts capitalized)........................  $  92,152     $  4,787   | $  95,509   $  99,961
                                                                    =========     ========   | =========   =========
     Income taxes (refund)........................................  $  83,776     $ 20,586   | $  19,365   $ (50,105)
                                                                    =========     ========   | =========   =========


         The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

                                                           16
</TABLE>

<PAGE>

<TABLE>

                                          JERSEY CENTRAL POWER & LIGHT COMPANY

                                            CONSOLIDATED STATEMENTS OF TAXES

<CAPTION>
                                                                                    Nov. 7 -      Jan. 1 -
                                                                        2002     Dec. 31, 2001  Nov. 6, 2001   2000
---------------------------------------------------------------------------------------------------------------------
                                                                                      (In thousands)
GENERAL TAXES:
<S>                                                                  <C>           <C>           <C>         <C>
Real and personal property.......................................    $  4,362      $     283   | $   3,589   $   4,093
State gross receipts.............................................          --          1,269   |        --          --
Social security and unemployment.................................          --             (1)  |         7          --
New Jersey Transitional Energy Facilities Assessment*............      39,387          6,765   |    42,418      47,521
Other............................................................      12,300            603   |    10,568      12,784
                                                                     --------      ---------   | ---------   ---------
       Total general taxes.......................................    $ 56,049      $   8,919   | $  56,582   $  64,398
                                                                     ========      =========   | =========   =========
                                                                                               |
PROVISION FOR INCOME TAXES:                                                                    |
Currently payable-                                                                             |
   Federal.......................................................    $ 55,731      $  11,827   | $  41,826   $(109,572)
   State.........................................................      13,809          3,205   |    19,415     (26,005)
                                                                     --------      ---------   | ---------   ---------
                                                                      `69,540         15,032   |    61,241    (135,577)
                                                                     --------      ---------   | ---------   ---------
Deferred, net-                                                                                 |
   Federal.......................................................      88,758          4,268   |   (36,210)    209,127
   State.........................................................      27,108          1,341   |   (21,922)     61,352
                                                                     --------      ---------   | ---------   ----------
                                                                      115,866          5,609   |   (58,132)    270,479
                                                                     --------      ---------   | ---------   ---------
Investment tax credit amortization...............................      (3,551)          (540)  |    (3,057)    (15,027)
                                                                     --------      ---------   | ---------   ---------
       Total provision for income taxes..........................    $181,855      $  20,101$  | $      52   $ 119,875
                                                                     ========      ==========  | =========   =========
                                                                                               |
INCOME STATEMENT CLASSIFICATION                                                                |
OF PROVISION FOR INCOME TAXES:                                                                 |
Operating income.................................................    $171,496      $  18,400   | $ 113,478   $ 124,019
Other income.....................................................      10,359          1,701   |  (113,426)     (4,144)
                                                                     --------      ---------   | ---------   ---------
       Total provision for income taxes..........................    $181,855      $  20,101   |        52   $ 119,875
                                                                     ========      =========   | =========   =========
                                                                                               |
RECONCILIATION OF FEDERAL INCOME TAX                                                           |
EXPENSE AT STATUTORY RATE TO TOTAL                                                             |
PROVISION FOR INCOME TAXES:                                                                    |
Book income before provision for income taxes....................    $433,749      $  50,142   | $  34,519   $ 330,688
                                                                     ========      =========   | =========   =========
Federal income tax expense at statutory rate.....................    $151,812      $  17,550   | $  12,082   $ 115,741
Increases (reductions) in taxes resulting from-                                                |
   Amortization of investment tax credits........................      (3,550)          (540)  |    (3,057)    (15,027)
   Depreciation..................................................       7,154            226   |     3,563       3,230
   State income tax, net of federal benefit......................      27,111          3,077   |     4,355      21,987
   Allocated share of consolidated tax savings...................          --             --   |    (8,509)         --
   Sale of generation assets.....................................          --             --   |        --      (6,239)
   Other, net....................................................        (672)          (212)  |    (8,382)        183
                                                                     --------      ---------   | ----------  ---------
       Total provision for income taxes..........................    $181,855      $  20,101   | $      52   $ 119,875
                                                                     ========      =========   | ==========  =========
                                                                                               |
ACCUMULATED DEFERRED INCOME TAXES AT                                                           |
DECEMBER 31:                                                                                   |
Property basis differences.......................................    $297,983      $ 288,255   |             $ 302,476
Nuclear decommissioning..........................................      44,775         59,716   |                97,817
Deferred sale and leaseback costs................................     (16,451)       (16,240)  |               (15,605)
Purchase accounting basis difference.............................      (1,253)       (71,900)  |                    --
Sale of generation assets........................................     (17,861)       184,625   |               235,923
Regulatory transition charge.....................................     224,117        123,042   |                99,930
Provision for rate refund........................................     (29,370)       (46,942)  |               (46,942)
Customer receivables for future income taxes.....................      (5,336)        16,749   |                33,234
Oyster Creek securitization......................................     202,448             --   |                    --
Other............................................................      (7,331)       (23,089)  |               (40,786)
                                                                     --------      ---------   |             ---------
       Net deferred income tax liability.........................    $691,721      $ 514,216   |             $ 666,047
                                                                     ========      =========   |             =========


* Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income.

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

                                                           17

</TABLE>


<PAGE>


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

        The  consolidated  financial  statements  include Jersey Central Power &
Light  Company  (Company)  and its wholly owned  subsidiaries.  All  significant
intercompany  transactions  have been eliminated.  The Company is a wholly owned
subsidiary  of  FirstEnergy  Corp.  FirstEnergy  also holds  directly all of the
issued and outstanding  common shares of Ohio Edison Company (OE), The Cleveland
Electric  Illuminating  Company (CEI), The Toledo Edison Company (TE),  American
Transmission  Systems,  Inc.  (ATSI),  Metropolitan  Edison Company (Met-Ed) and
Pennsylvania  Electric Company (Penelec).  The Company,  Met-Ed and Penelec were
formerly wholly owned  subsidiaries of GPU, Inc.,  which merged with FirstEnergy
on November 7, 2001.  Pre-merger and post-merger  period  financial  results are
separated by a heavy black line.

        The Company follows the accounting policies and practices  prescribed by
the Securities  and Exchange  Commission  (SEC),  the New Jersey Board of Public
Utilities  (NJBPU) and the Federal  Energy  Regulatory  Commission  (FERC).  The
preparation of financial  statements in conformity  with  accounting  principles
generally  accepted in the United  States  (GAAP)  requires  management  to make
periodic  estimates and assumptions  that affect the reported amounts of assets,
liabilities,  revenues and expenses and the disclosure of contingent  assets and
liabilities.  Actual  results could differ from these  estimates.  Certain prior
year  amounts  have  been   reclassified   to  conform  with  the  current  year
presentation.

   (A)  CONSOLIDATION-

        The  Company   consolidates  all  majority-owned   subsidiaries,   after
eliminating  the  effects  of  intercompany  transactions.   Non-majority  owned
investments,  including investments in limited liability companies, partnerships
and joint  ventures,  are accounted for under the equity method when the Company
is able to  influence  their  financial or operating  policies.  Investments  in
corporations  resulting  in voting  control  of 20% or more are  presumed  to be
equity method investments. Limited partnerships are evaluated in accordance with
SEC Staff D-46,  "Accounting for Limited  Partnership  Investments" and American
Institute of Certified Public  Accountants  (AICPA)  Statement of Position (SOP)
78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to
5  percent  threshold  for the  presumption  of  influence.  For  all  remaining
investments  (excluding  those  within  the  scope  of  Statement  of  Financial
Accounting Standards (SFAS) 115, the Company applies the cost method.

   (B)  REVENUES-

        The  Company's  principal  business  is  providing  electric  service to
customers in New Jersey.  The Company's  retail customers are metered on a cycle
basis.  Revenue is recognized for unbilled electric service provided through the
end of the year. See Note 7 - Other  Information  for discussion of reporting of
independent system operator transactions.

        Receivables from customers include sales to residential,  commercial and
industrial  customers  and sales to wholesale  customers.  There was no material
concentration  of receivables  as of December 31, 2002 or 2001,  with respect to
any particular segment of the Company's customers.

   (C)  REGULATORY PLAN-

        New  Jersey  continues  to  evolve  to a  competitive  electric  utility
marketplace.  In 2001, the NJBPU issued a Final Decision and Order (Final Order)
with respect to the Company's rate unbundling,  stranded cost and  restructuring
filings, which superseded its 1999 Summary Order. The Final Order confirmed rate
reductions  set  forth in the 1999  Summary  Order,  which  remain  in effect at
increasing levels through July 2003,  confirmed the right of customers to select
their generation supplier and deregulated electric generation service costs. The
Final  Order also  confirmed  the  establishment  of a  non-bypassable  societal
benefits charge to recover costs  including  nuclear plant  decommissioning  and
manufactured  gas  plant  remediation,   as  well  as  a  non-bypassable  market
transition  charge  primarily to recover  stranded costs. The NJBPU has deferred
making a final  determination  of the net proceeds and stranded costs related to
prior generating asset  divestitures until the Company's request for an Internal
Revenue  Service (IRS) ruling  regarding  the  treatment of  associated  federal
income tax benefits is acted upon.  Should the IRS ruling  support the return of
the tax benefits to  customers,  there would be no effect to the  Company's  net
income since the  contingency  existed  prior to the Company  being  acquired by
FirstEnergy.

        In  addition,  the Final Order  provided  for the ability to  securitize
stranded  costs  associated  with the divested  Oyster Creek Nuclear  Generating
Station.  In February 2002, the Company  received NJBPU  authorization  to issue
$320 million of transition  bonds to securitize the recovery of these costs. The
NJBPU order also  provided  for a  usage-based  non-bypassable  transition  bond
charge and for the  transfer  of the  bondable  transition  property  to another
entity.  JCP&L sold $320 million of  transition  bonds  through its wholly owned
subsidiary,  JCP&L  Transition  Funding  LLC,  in June  2002 - those  bonds  are
recognized on the Consolidated  Balance Sheet (see Note 4F).

                                       18

<PAGE>

        The  Company  obtains its supply of  electricity  almost  entirely  from
contracted  and open market  purchases.  The Company is  permitted  to defer for
future  collection  from  customers the amounts by which its costs for supplying
non-shopping   customers  and  costs  incurred  under   non-utility   generation
agreements exceed amounts  collected through its Basic Generation  Service (BGS)
and market  transition  charge rates.  As of December 31, 2002, the  accumulated
deferred cost balance totaled approximately $549 million. The NJBPU also allowed
securitization of the Company's  deferred balance to the extent permitted by law
upon  application  by the  Company  and a  determination  by the NJBPU  that the
conditions of the New Jersey restructuring  legislation are met. There can be no
assurance  as  to  the  extent,   if  any,  that  the  NJBPU  will  permit  such
securitization.

        Under New  Jersey  transition  legislation,  all  electric  distribution
companies,  including the Company, were required to file rate cases to determine
the level of unbundled rate  components to become  effective  August 1, 2003. On
August 1, 2002, the Company submitted two rate filings with the NJBPU. The first
filing requested  increases in base electric rates of approximately  $98 million
annually.  The  second  filing  was a request  to  recover  deferred  costs that
exceeded amounts being recovered under the current market  transition charge and
societal  benefits charge rates;  one proposed method of recovery of these costs
is the securitization of the deferred balance.  This securitization  methodology
is similar to the Oyster Creek securitization discussed above. Hearings began in
February 2003. The  Administrative  Law Judge's  recommended  decision is due in
June 2003 and the NJBPU's subsequent decision is due in July 2003.

        In December  2001,  the NJBPU  authorized  the auctioning of BGS for the
period from August 1, 2002 through July 31, 2003 to meet the electricity demands
of all  customers  who have not selected an  alternative  supplier.  The auction
results were approved by the NJBPU in February 2002,  removing the Company's BGS
obligation  of 5,100 MW for the period  August 1, 2002 through July 31, 2003. In
February  2003,  the NJBPU  approved  the BGS  auction  results  for the  period
beginning  August 1, 2003. The auction  covered a fixed price bid (applicable to
all  residential and smaller  commercial and industrial  customers) and a hourly
price bid (applicable to all large industrial  customers)  process.  The Company
will sell all self-supplied energy (non-utility generation and owned generation)
to the wholesale market with offsets to its deferred energy cost balances.

        The application of SFAS 71, "Accounting for the Effects of Certain Types
of  Regulation,"  was  discontinued  in  1999  with  respect  to  the  Company's
generation  operations.  The Company subsequently divested  substantially all of
its generating  assets.  The SEC issued  interpretive  guidance  regarding asset
impairment  measurement,  concluding that any supplemental  regulated cash flows
such as a Competitive  Transition  Charge should be excluded from the cash flows
of assets in a portion of the  business  not  subject to  regulatory  accounting
practices.   If  those  assets  are  impaired,  a  regulatory  asset  should  be
established if the costs are  recoverable  through  regulatory  cash flows.  Net
assets   included  in  utility  plant  relating  to  operations  for  which  the
application  of SFAS 71 was  discontinued  were $44 million as of  December  31,
2002.

   (D)  PROPERTY, PLANT AND EQUIPMENT-

        As a result of the merger,  a portion of the Company's  property,  plant
and equipment was adjusted to reflect fair value.  The majority of the Company's
property,  plant and  equipment is reflected at original  cost since such assets
remain subject to rate regulation on a historical cost basis. In addition to its
wholly owned  facilities,  the Company holds a 50%  ownership  interest in Yards
Creek Pumped Storage Facility,  and its net book value was  approximately  $21.3
million as of December 31, 2002.  The  Company's  accounting  policy for planned
major maintenance projects is to recognize liabilities as they are incurred.

        The  Company  provides  for  depreciation  on a  straight-line  basis at
various rates over the estimated lives of property included in plant in service.
The annualized  composite rate was approximately  3.5% in 2002, 3.4% in 2001 and
3.3% in 2000.

        Annual depreciation expense in 2002 included approximately $26.2 million
for future decommissioning costs applicable to the Company's ownership in Unit 2
of the Three Mile Island Nuclear Plant (TMI-2), a demonstration  nuclear reactor
(Saxton Nuclear Experimental Facility) owned by a wholly owned subsidiary of the
Company (in conjunction with Met-Ed and Penelec) and decommissioning liabilities
for its previously divested nuclear generating units. The Company's share of the
future obligation to decommission these units is approximately $132.0 million in
current dollars and (using a 4.0% escalation rate) approximately  $210.1 million
in  future  dollars.  The  estimated  obligation  and the  escalation  rate were
developed based on site specific studies.  Decommissioning  of the demonstration
nuclear   reactor  is  expected  to  be   completed   in  2003;   payments   for
decommissioning  of the nuclear  generating units are expected to begin in 2014,
when actual decommissioning work is expected to begin. The Company has recovered
approximately  $34.0  million for future  decommissioning  through its  electric
rates from customers  through December 31, 2002. The Company has also recognized
an estimated  liability of approximately $9.9 million related to decontamination
and  decommissioning  of nuclear  enrichment  facilities  operated by the United
States Department of Energy (DOE), as required by the Energy Policy Act of 1992.

                                       19

<PAGE>

        In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations".  The new statement  provides  accounting  standards for retirement
obligations  associated with tangible  long-lived assets, with adoption required
by January 1, 2003.  SFAS 143 requires that the fair value of a liability for an
asset  retirement  obligation be recorded in the period in which it is incurred.
The associated  asset  retirement  costs are capitalized as part of the carrying
amount of the long-lived  asset. Over time the capitalized costs are depreciated
and the present value of the asset retirement liability increases,  resulting in
a period expense.  However,  rate-regulated  entities may recognize a regulatory
asset or liability  instead,  if the criteria for such  treatment  are met. Upon
retirement,  a gain or  loss  would  be  recorded  if the  cost  to  settle  the
retirement obligation differs from the carrying amount.

          The Company has identified applicable legal obligations as defined
under the new standard, principally for nuclear power plant decommissioning.
Upon adoption of SFAS 143 in January 2003, asset retirement costs of $98 million
were recorded as part of the carrying amount of the related long-lived asset,
offset by accumulated depreciation of $98 million. The asset retirement
liability at the date of adoption was $104 million. As of December 31, 2002, the
Company had recorded decommissioning liabilities of $130 million. The change in
the estimated liabilities resulted from changes in methodology and various
assumptions, including changes in the projected dates for decommissioning.

        Management expects that substantially all of the nuclear decommissioning
costs will be  recoverable  through  regulated  rates.  Therefore,  the  Company
recognized a regulatory  liability of $26 million upon  adoption of SFAS 143 for
the transition amounts related to establishing the asset retirement  obligations
for nuclear decommissioning.

          The FASB approved SFAS 141, "Business Combinations" and SFAS 142,
"Goodwill and Other Intangible Assets," on June 29, 2001. SFAS 141 requires all
business combinations initiated after June 30, 2001, to be accounted for using
purchase accounting. The provisions of the new standard relating to the
determination of goodwill and other intangible assets have been applied to the
FirstEnergy/GPU merger, which was accounted for as a purchase transaction, and
have not materially affected the accounting for this transaction. Under SFAS
142, amortization of existing goodwill ceased January 1, 2002. Instead, goodwill
is tested for impairment at least on an annual basis - based on the results of
the transition analysis and the 2002 annual analysis, no impairment of the
Company's goodwill is required.

   (E)  STOCK-BASED COMPENSATION-

        FirstEnergy  applies  the  recognition  and  measurement  principles  of
Accounting  Principles  Board  Opinion  No. 25 (APB 25),  "Accounting  for Stock
Issued  to  Employees"  and  related   Interpretations  in  accounting  for  its
stock-based  compensation plans (see Note 4B). No material  stock-based employee
compensation  expense is  reflected in net income as all options  granted  under
those plans had an exercise  price equal to the market  value of the  underlying
common stock on the grant date, resulting in substantially no intrinsic value.

        If  FirstEnergy  had accounted for employee stock options under the fair
value method,  a higher value would have been  assigned to the options  granted.
The weighted average assumptions used in valuing the options and their resulting
estimated fair values would be as follows:

                                      2002           2001            2000
  ----------------------------------------------------------------------------
  Valuation assumptions:
    Expected option term (years).      8.1            8.3             7.6
    Expected volatility..........    23.31%         23.45%          21.77%
    Expected dividend yield......     4.36%          5.00%           6.68%
    Risk-free interest rate......     4.60%          4.67%           5.28%
  Fair value per option..........    $6.45          $4.97           $2.86
  ----------------------------------------------------------------------------

        The effects of applying fair value accounting to the FirstEnergy's stock
options would not materially affect the Company's net income.

                                       20

<PAGE>


   (F)  INCOME TAXES-

        Details  of the  total  provision  for  income  taxes  are  shown on the
Consolidated  Statements  of Taxes.  Deferred  income  taxes  result from timing
differences  in the  recognition of revenues and expenses for tax and accounting
purposes.  Investment tax credits,  which were deferred when utilized, are being
amortized over the recovery period of the related property. The liability method
is used to account for deferred  income taxes.  Deferred  income tax liabilities
related to tax and accounting basis  differences are recognized at the statutory
income tax rates in effect when the liabilities are expected to be paid. Results
for the period  January 1, 2001  through  November 6, 2001 were  included in the
final consolidated  federal income tax return of GPU, and results for the period
November 7, 2001 through December 31, 2001 were included in  FirstEnergy's  2001
consolidated  federal  income tax return.  The  consolidated  tax  liability  is
allocated on a "stand-alone" company basis, with the Company recognizing the tax
benefit for any tax losses or credits it contributed to the consolidated return.

   (G)  RETIREMENT BENEFITS-

        Effective  December 31, 2001, the Company's defined benefit pension plan
was merged  into  FirstEnergy's  defined  benefit  pension  plan.  FirstEnergy's
trusteed,  noncontributory defined benefit pension plan covers almost all of the
Company's  full-time  employees.  Upon retirement,  employees  receive a monthly
pension  based on length  of  service  and  compensation.  FirstEnergy  uses the
projected  unit credit  method for funding  purposes.  The assets of the pension
plan consist  primarily of common  stocks,  United States  government  bonds and
corporate  bonds.  Costs for the year 2001  include  the former  GPU  companies'
pension and other  postretirement  benefit costs for the period November 7, 2001
through December 31, 2001.

        The Company provides a minimum amount of noncontributory  life insurance
to retired employees in addition to optional contributory insurance. Health care
benefits,   which  include  certain  employee  contributions,   deductibles  and
copayments, are also available to retired employees, their dependents and, under
certain circumstances,  their survivors.  The Company pays insurance premiums to
cover a portion of these benefits in excess of set limits; all amounts up to the
limits are paid by the Company.  The Company  recognizes  the  expected  cost of
providing other postretirement benefits to employees and their beneficiaries and
covered  dependents from the time employees are hired until they become eligible
to receive those benefits.

        The  following  sets  forth the funded  status of the plans and  amounts
recognized on FirstEnergy's Consolidated Balance Sheet as of December 31:

                                       21

<PAGE>


<TABLE>
<CAPTION>
                                                                                   Other
                                                   Pension Benefits      Postretirement Benefits
                                                   ----------------      -----------------------
                                                   2002        2001          2002         2001
------------------------------------------------------------------------------------------------
                                                                  (In millions)
     Change in benefit obligation:
<S>                                              <C>         <C>          <C>          <C>
     Benefit obligation as of January 1........  $3,547.9    $1,506.1     $ 1,581.6    $   752.0
     Service cost..............................      58.8        34.9          28.5         18.3
     Interest cost.............................     249.3       133.3         113.6         64.4
     Plan amendments...........................      --           3.6        (121.1)        --
     Actuarial loss............................     268.0       123.1         440.4         73.3
     Voluntary early retirement program........      --          --            --            2.3
     GPU acquisition...........................     (11.8)    1,878.3         110.0        716.9
     Benefits paid.............................    (245.8)     (131.4)        (83.0)       (45.6)
     -------------------------------------------------------------------------------------------
     Benefit obligation as of December 31......   3,866.4     3,547.9       2,070.0      1,581.6
     -------------------------------------------------------------------------------------------

     Change in fair value of plan assets:
     Fair value of plan assets as of January 1.   3,483.7     1,706.0         535.0         23.0
     Actual return on plan assets..............    (348.9)        8.1         (57.1)        12.7
     Company contribution......................      --          --            37.9         43.3
     GPU acquisition...........................      --       1,901.0          --          462.0
     Benefits paid.............................    (245.8)     (131.4)        (42.5)        (6.0)
     -------------------------------------------------------------------------------------------
     Fair value of plan assets as of December 31  2,889.0       3,483.7        473.3       535.0
     --------------------------------------------------------------------------------------------
     Funded status of plan.....................    (977.4)      (64.2)     (1,596.7)    (1,046.6)
     Unrecognized actuarial loss...............   1,185.8       222.8         751.6        212.8
     Unrecognized prior service cost...........      78.5        87.9        (106.8)        17.7
     Unrecognized net transition obligation....      --          --            92.4        101.6
     -------------------------------------------------------------------------------------------
     Net amount recognized.....................  $  286.9    $  246.5     $  (859.5)   $  (714.5)
     ===========================================================================================

     Consolidated Balance Sheets classifications:
     Prepaid (accrued) benefit cost............   $(548.6)   $  246.5     $  (859.5)   $  (714.5)
     Intangible asset..........................      78.5        --            --           --
     Accumulated other comprehensive loss......     757.0        --            --           --
     -------------------------------------------------------------------------------------------
     Net amount recognized.....................   $ 286.9    $  246.5     $  (859.5)   $  (714.5)
     ============================================================================================

     Assumptions used as of December 31:
     Discount rate.............................      6.75%       7.25%         6.75%       7.25%
     Expected long-term return on plan assets..      9.00%      10.25%         9.00%      10.25%
     Rate of compensation increase.............      3.50%       4.00%         3.50%       4.00%

        Net pension  and other  postretirement  benefit  costs for the two years
ended December 31, 2002 were computed as follows:
<CAPTION>
                                                                                        Other
                                                  Pension Benefits              Postretirement Benefits
                                                --------------------            -----------------------
                                                 2002        2001                 2002         2001
     --------------------------------------------------------------------------------------------------
                                                                     (In millions)

<S>                                           <C>         <C>        <C>        <C>           <C>
     Service cost...........................   $  58.8     $  34.9               $ 28.5       $18.3
     Interest cost..........................     249.3       133.3                113.6        64.4
     Expected return on plan assets.........    (346.1)     (204.8)               (51.7)       (9.9)
     Amortization of transition obligation
       (asset)..............................        --        (2.1)                 9.2         9.2
     Amortization of prior service cost.....       9.3         8.8                  3.2         3.2
     Recognized net actuarial loss (gain)...        --          --                 11.2         4.9
     Voluntary early retirement program.....        --         6.1                   --         2.3
     --------------------------------------------------------------------------------------------------
     Net periodic benefit cost (income).....   $ (28.7)    $ (23.8)              $114.0       $92.4
     ==================================================================================================

</TABLE>


        The composite  health care cost trend rate  assumption is  approximately
10%-12% in 2003,  9% in 2004 and 8% in 2005,  decreasing  to 5% in later  years.
Assumed  health care cost trend rates have a  significant  effect on the amounts
reported  for the health  care plan.  An  increase in the health care cost trend
rate  assumption by one  percentage  point would  increase the total service and
interest  cost  components  by  $20.7  million  and the  postretirement  benefit
obligation  by  $232.2  million.  A  decrease  in  the  same  assumption  by one
percentage  point would decrease the total service and interest cost  components
by $16.7 million and the postretirement benefit obligation by $204.3 million.

        A significant  portion of the services  provided to the Company are from
affiliates, GPU Service, Inc. (GPUS) and FirstEnergy Service Company (FECO) (see
Note 1H).  Therefore,  substantially  all of the  employees  are with GPUS which
bills the Company for services rendered. See Note 7D for the Company's amount of
net pension and other postretirement benefit costs reflected in its Consolidated
Statements of Income.

                                       22


<PAGE>


   (H)  TRANSACTIONS WITH AFFILIATED COMPANIES-

        Operating   revenues,   operating  expenses  and  other  income  include
transactions with affiliated companies, primarily GPUS and FirstEnergy Solutions
(FES).  During the three years ended  December 31, 2002,  GPUS  provided  legal,
accounting,  financial  and other  services to the  Company.  The  Company  also
entered into sale and purchase transactions with affiliates (Met-Ed and Penelec)
during the period. Through the BGS auction process, FES is an alternate supplier
of power to the Company.

        FirstEnergy  does not bill  directly or allocate any of its costs to any
subsidiary company. Costs are allocated to the Company from its affiliates, GPUS
and FECO,  both  subsidiaries  of  FirstEnergy  Corp.  and both "mutual  service
companies" as defined in Rule 93 of the 1935 Public Utility  Holding Company Act
(PUHCA).  The majority of costs are directly  billed or assigned at no more than
cost as determined  by PUHCA Rule 91. The remaining  costs are for services that
are  provided  on behalf  of more  than one  company,  or costs  that  cannot be
precisely  identified  and are allocated  using formulas that are filed annually
with the SEC on Form U-13-60. The current allocation or assignment formulas used
and their bases include  multiple factor  formulas:  the ratio of each company's
amount of  FirstEnergy's  aggregate direct payroll,  number of employees,  asset
balances,  revenues,  number  of  customers  and  other  factors;  and  specific
departmental  charge ratios.  Management  believes that these allocation methods
are reasonable.

   (I)  SUPPLEMENTAL CASH FLOWS INFORMATION-

        All temporary cash  investments  purchased  with an initial  maturity of
three  months  or less are  reported  as cash  equivalents  on the  Consolidated
Balance Sheets at cost, which approximates their fair market value.

        All borrowings with initial maturities of less than one year are defined
as financial instruments under GAAP and are reported on the Consolidated Balance
Sheets at cost, which  approximates  their fair market value. The following sets
forth the  approximate  fair  value and  related  carrying  amounts of all other
long-term debt,  preferred stock subject to mandatory redemption and investments
other than cash and cash equivalents as of December 31:

                                                2002               2001
-------------------------------------------------------------------------------
                                       Carrying    Fair     Carrying     Fair
                                        Value      Value     Value       Value
-------------------------------------------------------------------------------
                                                    (In millions)
Long-term debt.....................     $1,374    $ 1,415    $1,246     $1,250
Preferred stock....................     $  125    $   127    $  176     $  180
Investments other than cash
  and cash equivalents.............     $  258    $   258    $  253     $  252

        The fair  values of  long-term  debt and  preferred  stock  reflect  the
present value of the cash  outflows  relating to those  securities  based on the
current  call  price,  the yield to  maturity  or the  yield to call,  as deemed
appropriate at the end of each respective year. The yields assumed were based on
securities  with similar  characteristics  offered by  corporations  with credit
ratings similar to the Company's ratings. In 2001,  long-term debt and preferred
stock  subject  to  mandatory  redemption  were  recognized  at  fair  value  in
connection with the merger.

        The fair  value of  investments  other  than  cash and cash  equivalents
represents cost (which approximates fair value) or the present value of the cash
inflows  based on the  yield to  maturity.  The  yields  assumed  were  based on
financial instruments with similar characteristics and terms.  Investments other
than cash and cash equivalents include  decommissioning  trust investments.  The
Company has no securities held for trading purposes.

        The  investment  policy  for the  nuclear  decommissioning  trust  funds
restricts  or limits  the  ability  to hold  certain  types of assets  including
private or direct placements,  warrants, securities of FirstEnergy,  investments
in companies  owning  nuclear power  plants,  financial  derivatives,  preferred
stocks,  securities  convertible  into common stock and  securities of the trust
fund's custodian or managers and their parents or subsidiaries.  The investments
that are held in the decommissioning trusts (included as "Investments other than
cash and cash  equivalents"  in the table above)  consist of equity  securities,
government bonds and corporate bonds.  Unrealized gains and losses applicable to
the  decommissioning  trusts have been recognized in the trust investment with a
corresponding change to the decommissioning  liability.  Realized gains (losses)
are recognized as additions  (reductions) to trust asset balances.  For the year
2002,  net realized  losses were  approximately  $0.06  million and interest and
dividend income totaled approximately $3.6 million.

        On  January 1, 2001,  the  Company  adopted  SFAS 133,  "Accounting  for
Derivative  Instruments  and  Hedging  Activities,"  as  amended  by  SFAS  138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities --
an  amendment  of  FASB  Statement  No.  133."  The  adoption  resulted  in  the
recognition of derivative assets on the Consolidated Balance Sheet as of January
1, 2001 in the amount of $21.8  million  with  offsetting  amounts,  net of tax,
recorded in Accumulated  Other  Comprehensive  Income,  of $5.1 million,  and in
Regulatory Assets, of $13 million.

        The Company is exposed to financial risks resulting from the fluctuation
of  commodity  prices,  including  electricity  and  natural  gas. To manage the
volatility  relating  to  these  exposures,   the  Company  uses  a  variety  of
non-derivative and derivative instruments,  including forward contracts, options
and  futures  contracts.  These  derivatives  are used  principally  for hedging
purposes.  The Company has a Risk Policy  Committee,  comprised  of  FirstEnergy
executive  officers,  which exercises an independent risk oversight  function to
ensure  compliance  with  corporate  risk  management  policies and prudent risk
management practices.

        The Company uses  derivatives  to hedge the risk of price  fluctuations.
The Company's  primary  ongoing  hedging  activity  involves cash flow hedges of
electricity  and natural gas  purchases.  The majority of the Company's  forward
commodity  contracts are considered  "normal purchases and sales," as defined by
SFAS 133,  and are  therefore  excluded  from the scope of SFAS 138. The forward
contracts,  options and futures  contracts  determined to be within the scope of
SFAS 133 are  accounted  for as cash flow  hedges and  expire on  various  dates
through 2003. Gains and losses from hedges of commodity price risks are included
in net income when the underlying  hedged  commodities  are delivered.  There is
currently a net deferred  loss of $0.4  million  included in  Accumulated  Other
Comprehensive  Loss as of  December  31,  2002  related  to  derivative  hedging
activity,  which will be  reclassified to earnings during the next twelve months
as hedged transactions occur.

   (J)  REGULATORY ASSETS-

        The Company recognizes,  as regulatory assets,  costs which the FERC and
NJBPU have  authorized  for recovery from customers in future  periods.  Without
such authorization, the costs would have been charged to income as incurred. All
regulatory  assets are expected to continue to be recovered from customers under
the  Company's  regulatory  plan.  The  Company  continues  to bill and  collect
cost-based rates for its transmission  and distribution  services,  which remain
regulated;  accordingly,  it is  appropriate  that  the  Company  continues  the
application  of  SFAS 71 to  those  operations.

        Net regulatory  assets on the Consolidated  Balance Sheets are comprised
of the following:

                                                      2002               2001
  -----------------------------------------------------------------------------
                                                            (In millions)

  Regulatory transition charge...................   $2,801.7           $2,844.7
  Societal benefits charge.......................      143.8              166.6
  Property losses and unrecovered plant costs....       87.8              104.1
  Customer receivables for future income taxes...       34.5               52.4
  Employee postretirement benefit costs..........       33.2               36.5
  Loss on reacquired debt........................       17.4               19.3
  Spent fuel disposal costs......................        8.8               20.2
  Other..........................................       71.8               81.0
  -----------------------------------------------------------------------------
     Total.......................................   $3,199.0           $3,324.8
  =============================================================================

2.  MERGER:

        On November 7, 2001, the merger of FirstEnergy and GPU became  effective
pursuant to the Agreement and Plan of Merger,  dated August 8, 2000. As a result
of the merger,  GPU's former wholly owned  subsidiaries,  including the Company,
became wholly owned subsidiaries of FirstEnergy.

        The merger was accounted for by the purchase  method of accounting.  The
assets acquired and  liabilities  assumed were recorded at estimated fair values
as  determined  by  FirstEnergy's  management  based  on  information  currently
available and on current  assumptions as to future  operations.  Merger purchase
accounting  adjustments recorded in the records of the Company primarily consist
of: (1)  revaluation of certain  property,  plant and  equipment;  (2) adjusting
preferred stock subject to mandatory  redemption and long-term debt to estimated
fair  value;  (3)  recognizing  additional  obligations  related  to  retirement
benefits;  and  (4)  recognizing  estimated  severance  and  other  compensation
liabilities.  Other assets and  liabilities  were not adjusted since they remain
subject  to rate  regulation  on a  historical  cost  basis.  The  excess of the
purchase  price  over the  estimated  fair  values of the  assets  acquired  and
liabilities  assumed was recognized as goodwill.

        During  2002,  certain  pre-acquisition  contingencies  and other  final
adjustments to the fair values of the assets  acquired and  liabilities  assumed
were reflected in the final allocation of the purchase price.  These adjustments
primarily  related to: (1) final actuarial  calculations  related to pension and
postretirement  benefit  obligations  and (2) return to accrual  adjustments for
income  taxes.  As  a  result  of  these  adjustments,   goodwill  increased  by
approximately  $74.3 million.  As of December 31, 2002, the Company had recorded
goodwill of approximately $2.0 billion related to the merger.


                                       24

<PAGE>


3.  LEASES:

        Consistent  with  regulatory  treatment,  the  rentals  for  capital and
operating  leases  are  charged  to  operating   expenses  on  the  Consolidated
Statements  of Income.  Prior to the sale of its nuclear  generating  facilities
(completed in 2000), the Company's capital lease  obligations  related primarily
to nuclear fuel lease agreements with  nonaffiliated fuel trusts for the plants.
In 2000,  total  rentals  related to these  capital  leases were $13.0  million,
comprised  of an  interest  element  of $1.5  million  and other  costs of $11.5
million. The Company's most significant  operating lease relates to the sale and
leaseback of a portion of its ownership  interest in the Merrill Creek Reservoir
project.  The  interest  element  related to this lease was $1.2  million,  $1.2
million and $0.4 million for the years 2002, 2001 and 2000, respectively.

        As of  December  31,  2002,  the future  minimum  lease  payments on the
Company's Merrill Creek operating lease, net of reimbursements  from sublessees,
are: $3.2 million, $1.2 million, $1.7 million, $1.6 million and $1.6 million for
the years 2003  through  2007,  respectively,  and $56.7  million  for the years
thereafter.  The Company is recovering its Merrill Creek lease payments,  net of
reimbursements, through its distribution rates.

4.  CAPITALIZATION:

   (A)  RETAINED EARNINGS-

        The  merger  purchase  accounting  adjustments  included  resetting  the
retained earnings balance to zero as of the November 7, 2001 merger date.

        In general,  the Company's first mortgage bond (FMB) indentures restrict
the payment of dividends or  distributions  on or with respect to the  Company's
common stock to amounts credited to earned surplus since  approximately the date
of its indenture. At such date, the Company had a balance of $1.7 million in its
earned  surplus  account,  which would not be available  for  dividends or other
distributions.  As of December  31,  2002,  the Company  had  retained  earnings
available  to pay  common  stock  dividends  of $90.3  million,  net of  amounts
restricted under the Company's FMB indentures.

   (B)  STOCK COMPENSATION PLANS-

        In 2001,  FirstEnergy  assumed  responsibility  for two new  stock-based
plans as a result of its acquisition of GPU. No further stock-based compensation
can be awarded under the GPU, Inc.  Stock Option and  Restricted  Stock Plan for
MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU,
Inc. and  Subsidiaries  (GPU Plan).  All options and restricted stock under both
Plans have been converted into FirstEnergy options and restricted stock. Options
under the GPU Plan became fully  vested on November 7, 2001,  and will expire on
or before June 1, 2010.  Under the MYR Plan,  all options and  restricted  stock
maintained their original  vesting periods,  which range from one to four years,
and will expire on or before December 17, 2006.

        Additional  stock based plans  administered  by FirstEnergy  include the
Centerior  Equity  Plan (CE Plan) and the  FirstEnergy  Executive  and  Director
Incentive Compensation Plan (FE Plan). All options are fully vested under the CE
Plan, and no further awards are permitted. Outstanding options will expire on or
before  February 25, 2007.  Under the FE Plan,  total awards  cannot exceed 22.5
million  shares of common  stock or their  equivalent.  Only stock  options  and
restricted stock have been granted, with vesting periods ranging from six months
to seven years.

        Collectively,  the  above  plans  are  referred  to as the FE  Programs.
Restricted common stock grants under the FE Programs were as follows:

                                               2002       2001        2000
------------------------------------------------------------------------------

  Restricted common shares granted.........   36,922     133,162     208,400
  Weighted average market price ...........   $36.04     $35.68      $26.63
  Weighted average vesting period (years)..   3.2        3.7         3.8
  Dividends restricted.....................   Yes        *           Yes
  ----------------------------------------------------------------------------

* FE Plan  dividends  are paid as  restricted  stock on 4,500  shares;  MYR Plan
  dividends are paid as unrestricted cash on 128,662 shares

        Under the Executive Deferred Compensation Plan (EDCP), covered employees
can direct a portion of their Annual Incentive Award and/or Long-Term  Incentive
Award into an unfunded  FirstEnergy Stock Account to receive vested stock units.
An  additional  20%  premium is received in the form of stock units based on the
amount  allocated to the  FirstEnergy  Stock  Account.  Dividends are calculated
quarterly  on stock  units  outstanding  and are paid in the form of  additional
stock units. Upon withdrawal,  stock units are converted to FirstEnergy  shares.
Payout  typically  occurs  three years from the date of  deferral;  however,  an
election can be made in the year prior to payout to further  defer shares into a
retirement  stock  account  that  will pay out in cash  upon  retirement.  As of
December 31, 2002, there were 296,008 stock units outstanding.

                                       25

<PAGE>


        Stock option  activities  under the FE Programs for the past three years
were as follows:

                                            Number of      Weighted Average
       Stock Option Activities               Options        Exercise Price
------------------------------------------------------------------------------
  Balance, January 1, 2000...............   2,153,369          $25.32
  (159,755 options exercisable)..........                       24.87

    Options granted......................   3,011,584           23.24
    Options exercised....................      90,491           26.00
    Options forfeited....................      52,600           22.20
  Balance,  December 31, 2000............   5,021,862           24.09
  (473,314 options exercisable)..........                       24.11

    Options granted......................   4,240,273           28.11
    Options exercised....................     694,403           24.24
    Options forfeited....................     120,044           28.07
  Balance, December 31, 2001.............   8,447,688           26.04
  (1,828,341 options exercisable)........                       24.83

    Options granted......................   3,399,579           34.48
    Options exercised....................   1,018,852           23.56
    Options forfeited....................     392,929           28.19
  Balance,  December 31, 2002............  10,435,486           28.95
  (1,400,206 options exercisable)........                       26.07


        As of December 31, 2002, the weighted average remaining contractual life
of outstanding stock options was 7.6 years.

        No material  stock-based  employee  compensation expense is reflected in
net income for stock  options  granted  under the above plans since the exercise
price was equal to the market value of the underlying  common stock on the grant
date.  The effect of  applying  fair value  accounting  to  FirstEnergy's  stock
options is summarized in Note 1E - Stock-Based Compensation.

   (C)  PREFERRED AND PREFERENCE STOCK-

        Preferred  stock may be  redeemed by the  Company,  in whole or in part,
with 30-90 days' notice.

   (D)  COMPANY-OBLIGATED  MANDATORILY  REDEEMABLE  PREFERRED  SECURITIES  OF
        LIMITED PARTNERSHIP HOLDING SOLELY COMPANY SUBORDINATED DEBENTURES-

        JCP&L Capital, L.P. is a special-purpose  limited partnership in which a
subsidiary of the Company is the sole general partner.  The limited  partnership
invested the gross  proceeds from the sale of $125.0 million at 8.56% of monthly
income  preferred  securities  (MIPS) in $128.9  million of the Company's  8.56%
subordinated  debentures.  The sole assets of the limited  partnership are these
subordinated  debentures,  which  have the same  rate and  maturity  date as the
preferred   securities.   The  Company  has  effectively  provided  a  full  and
unconditional guarantee of its obligations under its limited partnership's MIPS,
to the extent that there is sufficient  cash on hand to permit such payments and
funds legally available therefor, and payments on liquidation or redemption with
respect  to the  MIPS.  Distributions  on the  limited  partnership's  MIPS (and
interest on the  subordinated  debentures)  may be deferred for up to 60 months,
but the  Company  may not pay  dividends  on, or redeem or  acquire,  any of its
cumulative preferred or common stock until deferred payments on its subordinated
debentures are paid in full.  The limited  partnership's  MIPS,  which mature in
2044 and have a liquidation value of $25.00 per security,  are redeemable at the
option of the Company at 100% of their principal amount.

                                       26

<PAGE>


   (E)  LONG-TERM DEBT-

        The Company's  first mortgage bond  indenture,  which secures all of the
Company's FMBs,  serve as a direct first mortgage lien on  substantially  all of
the  Company's  property  and  franchises,   other  than  specifically  excepted
property.

        The Company has various debt covenants under its financing arrangements.
The most  restrictive  of these  relate to the  nonpayment  of  interest  and/or
principal on debt, which could trigger a default.  Cross-default provisions also
exist between FirstEnergy and the Company.

        Based  on the  amount  of bonds  authenticated  by the  Trustee  through
December 31, 2002 the Company's  annual  improvement  fund  requirements for all
bonds issued under the mortgage amount to $15.7 million.  The Company expects to
fulfill its  improvement  fund obligation by providing  refundable  bonds to the
Trustee.

        Sinking  fund   requirements  for  FMBs  and  maturing   long-term  debt
(excluding capital leases) for the next five years are:

                                         (In millions)
                            ------------------------
                              2003........  $173.8
                              2004........   175.9
                              2005........    66.9
                              2006........   230.6
                              2007........    36.7
                            -------------------------


   (F)  SECURITIZED TRANSITION BONDS-

        On June 11, 2002, JCP&L Transition Funding LLC (Issuer),  a wholly owned
limited liability company of the Company,  sold $320 million of transition bonds
to securitize the recovery of the Company's  bondable  stranded costs associated
with the previously divested Oyster Creek Nuclear Generating Station.

        The  Company  does  not own nor did it  purchase  any of the  transition
bonds,  which are included in long-term  debt on and the Company's  Consolidated
Balance Sheet. The transition bonds represent obligations only of the Issuer and
are collateralized  solely by the equity and assets of the Issuer, which consist
primarily of bondable transition  property.  The bondable transition property is
solely the property of the Issuer.

        Bondable  transition  property  represents  the  irrevocable  right of a
utility  company to charge,  collect and receive from its  customers,  through a
non-bypassable  transition bond charge, the principal amount and interest on the
transition bonds and other fees and expenses associated with their issuance. The
Company, as servicer,  manages and administers the bondable transition property,
including the billing,  collection and remittance of the transition bond charge,
pursuant to a servicing  agreement with the Issuer. The Company is entitled to a
quarterly  servicing fee of $100,000 that is payable from transition bond charge
collections.

   (G)  COMPREHENSIVE INCOME-

        Comprehensive income includes net income as reported on the Consolidated
Statements of Income and all other changes in common stockholder's equity except
those resulting from  transactions with the Company's parent. As of December 31,
2002,  accumulated  other  comprehensive  loss consisted of unrealized losses on
derivative instrument hedges of $0.9 million.

5.  SHORT-TERM BORROWINGS:

        The Company may borrow from its affiliates on a short-term  basis. As of
December 31, 2002, the Company had no short-term borrowings outstanding.

6. COMMITMENTS, GUARANTEES AND CONTINGENCIES:

   (A)  CAPITAL EXPENDITURES-

        The Company's  current forecast  reflects  expenditures of approximately
$462 million for property  additions and improvements from 2003 through 2007, of
which approximately $102 million is applicable to 2003.

   (B)  NUCLEAR INSURANCE-

        The  Price-Anderson Act limits the public liability relative to a single
incident at a nuclear  power plant to $9.5  billion.  The amount is covered by a
combination  of private  insurance  and an industry  retrospective  rating plan.
Based on

                                       27

<PAGE>

its  present  ownership  interest  in TMI-2,  the  Company  is  exempt  from any
potential assessment under the industry retrospective rating plan.

        The Company is also  insured as to its  interest in TMI-2 under a policy
issued to the operating company for the plant.  Under this policy,  $150 million
is provided for property damage and decontamination  and decommissioning  costs.
Under this policy,  the Company can be assessed a maximum of approximately  $0.2
million for incidents at any covered nuclear facility  occurring during a policy
year which are in excess of  accumulated  funds  available  to the  insurer  for
paying losses.

        The  Company  intends to maintain  insurance  against  nuclear  risks as
described above as long as it is available.  To the extent that property damage,
decontamination,  decommissioning,  repair and replacement  costs and other such
costs  arising from a nuclear  incident at TMI-2 exceed the policy limits of the
insurance in effect with respect to that plant, to the extent a nuclear incident
is determined not to be covered by the Company's insurance  policies,  or to the
extent such  insurance  becomes  unavailable  in the future,  the Company  would
remain at risk for such costs.

   (C)  ENVIRONMENTAL MATTERS-

        The Company has been named as a "potentially responsible party" (PRP) at
waste  disposal  sites  which  may  require  cleanup  under  the   Comprehensive
Environmental  Response,  Compensation and Liability Act of 1980. Allegations of
disposal of hazardous  substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute;  however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore,  potential  environmental  liabilities  have been  recognized  on the
Consolidated  Balance  Sheet as of December 31, 2002,  based on estimates of the
total costs of cleanup,  the  Company's  proportionate  responsibility  for such
costs and the  financial  ability of other  nonaffiliated  entities  to pay.  In
addition,  the Company has accrued liabilities for environmental  remediation of
former  manufactured  gas plants in New Jersey;  those costs are being recovered
through a non-bypassable societal benefits charge. The Company has total accrued
liabilities aggregating approximately $47.1 million as of December 31, 2002. The
Company does not believe  environmental  remediation  costs will have a material
adverse effect on its financial condition, cash flows or results of operations.

   (D)  OTHER LEGAL PROCEEDINGS-

        Various lawsuits, claims and proceedings related to the Company's normal
business  operations are pending  against the Company,  the most  significant of
which are described below.

        The Company  has a 25%  ownership  interest in TMI-2,  which was damaged
during a 1979 accident. As a result of the accident, claims for alleged personal
injury were filed against the Company,  Met-Ed, Penelec and GPU (the defendants)
in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the
District Court granted a motion for summary judgment filed by the defendants and
dismissed  the ten initial  "test cases" which had been selected for a test case
trial.  In January 2002,  the District Court granted the  defendants'  July 2001
motion for summary  judgment on the remaining 2,100 pending claims.  In February
2002,  the  plaintiffs  filed a notice of appeal to the United  States  Court of
Appeals for the Third Circuit. In December 2002, the Court of Appeals refused to
hear the appeal, which effectively ended further legal action for those claims.

        In July 1999, the  Mid-Atlantic  states  experienced a severe heat storm
which  resulted in power  outages  throughout  the service  territories  of many
electric  utilities,  including  the service  territory  of the  Company.  In an
investigation  into  the  causes  of the  outages  and  the  reliability  of the
transmission and distribution systems of all four New Jersey electric utilities,
the NJBPU  concluded that there was not a prima facie case  demonstrating  that,
overall,  the Company  provided  unsafe,  inadequate or improper  service to its
customers.  In July 1999, two class action lawsuits  (subsequently  consolidated
into a single  proceeding)  were filed in New Jersey  Superior Court against the
Company and other GPU  companies,  seeking  compensatory  and  punitive  damages
arising  from the July  1999  service  interruptions  in the  Company's  service
territory.  In May 2001, the court denied without prejudice the Company's motion
seeking  decertification of the class.  Discovery continues in the class action,
but no trial date has been set. In October 2001,  the court held argument on the
plaintiffs' motion for partial summary judgment, which contends that the Company
is bound to several findings of the NJBPU investigation.  The plaintiffs' motion
was denied by the Court in November 2001 and the  plaintiffs'  motion to file an
appeal of this  decision was denied by the New Jersey  Appellate  Division.  The
Company has also filed a motion for partial  summary  judgment that is currently
pending before the Superior Court.  The Company is unable to predict the outcome
of these matters.

                                       28

<PAGE>


7.  OTHER INFORMATION:

          The following represents the financial data which includes
supplemental unaudited prior years' information as compared to consolidated
financial statements and notes previously reported in 2001 and 2000.

   (A)  CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                     Nov. 7-      Jan. 1-
                                                                     Dec. 31,     Nov. 6,
                                                          2002        2001         2001       2002
                                                          ----        ----         ----       ----
         Other Cash Flows from Operating Activities:
<S>                                                    <C>          <C>          <C>       <C>
         Accrued taxes.............................    $(21,939)    $ 2,675  |   $24,272   $   4,242
         Accrued interest..........................       1,625       9,501  |    (7,590)        898
         Retail rate refunds obligation payments...     (43,016)         --  |        --          --
         Prepayments and other.....................     (21,149)     16,436  |    63,909     (73,916)
         All other.................................      66,837      (8,049) |   (14,263)   (161,324)
                                                       --------     -------- |   -------   ---------
           Other cash used for operating activities    $(17,642)    $20,563  |   $66,328   $(230,100)
                                                       ========     =======  |   =======   =========
</TABLE>

   (B)  REVENUES - INDEPENDENT SYSTEM OPERATOR (ISO) TRANSACTIONS

        The  Company   records   purchase  and  sales   transactions   with  PJM
Interconnection  ISO,  an  independent  system  operator,  on a gross  basis  in
accordance  with EITF Issue No. 99-19,  "Reporting  Revenue Gross as a Principal
versus Net as an Agent." The aggregate  purchase and sales  transactions for the
three years ended December 31, 2002, are summarized as follows:

                              Nov. 7-Dec. 31,  Jan. 1-Nov. 6,
                        2002       2001            2001       2000
            -------------------------------------------------------
                                     (In millions)
            Sales.....  $136       $  2    |       $  28      $87
            Purchases.   101         16    |         188       66
            -------------------------------|-----------------------


        The Company's revenues on the Consolidated  Statements of Income include
wholesale  electricity  sales  revenues  from the PJM ISO from  power  sales (as
reflected in the table  above)  during  periods when the Company had  additional
available  power  capacity.  Revenues also include sales by the Company of power
sourced from the PJM ISO  (reflected  as  purchases  in the table above)  during
periods  when the  Company  required  additional  power to meet its retail  load
requirements.

   (C)      TRANSACTIONS WITH AFFILIATED COMPANIES-

        The primary affiliated companies transactions are as follows:

                                                 Nov. 7-     Jan. 1-
                                                 Dec. 31,     Nov. 6,
                                         2002      2001        2001      2000
------------------------------------------------------------------------------
                                                    (In millions)
Operating Revenues:
Wholesale sales-affiliated companies... $  17.6   $  2.4   |   $17.3   $   3.0
                                                           |
Operating Expenses:                                        |
GPU Service, Inc. support services.....   140.4     21.0   |   120.0     259.0
Power purchased from other affiliates..    26.1      3.4   |    16.1      48.1
Power purchased from FES...............    17.9      7.5   |      --        --
-----------------------------------------------------------------------------

   (D)  RETIREMENTS BENEFITS (1)

        Net pension and other  postretirement  benefit  costs  (income)  for the
three years ended December 31, 2002 are approximately as follows:

                                                 Nov. 7-     Jan. 1-
                                                 Dec. 31,     Nov. 6,
                                         2002      2001        2001      2000
------------------------------------------------------------------------------
                                                    (In millions)
Pension Benefits....................... $(19.6)   $(6.7)  |  $(33.4)    $(10.6)
Other Postretirement Benefits..........    5.3      1.7   |     8.3       14.9
------------------------------------------------------------------------------

(1) Includes estimated portion of benefit costs included in billings from GPUS.

                                       29

<PAGE>

8 . RECENTLY ISSUED ACCOUNTING STANDARDS:

        FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure
        Requirements   for   Guarantees,   Including   Indirect   Guarantees  of
        Indebtedness of Others - an interpretation of FASB Statements No. 5, 57,
        and 107 and rescission of FASB Interpretation No. 34"

        The FASB issued FIN 45 in January 2003. This  interpretation  identifies
minimum guarantee  disclosures required for annual periods ending after December
15, 2002. It also clarifies  that  providers of guarantees  must record the fair
value of those  guarantees  at their  inception.  This  accounting  guidance  is
applicable  on a  prospective  basis to  guarantees  issued  or  modified  after
December 31, 2002.  The Company does not believe that  implementation  of FIN 45
will be material but it will continue to evaluate anticipated guarantees.

        FIN 46, "Consolidation of Variable Interest Entities - an interpretation
        of ARB 51"

        In January  2003,  the FASB  issued this  interpretation  of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities  in  which  equity  investors  do not  have  the  characteristics  of a
controlling  financial interest or do not have sufficient equity at risk for the
entity to finance  its  activities  without  additional  subordinated  financial
support  from other  parties.  This  interpretation  requires an  enterprise  to
disclose  the  nature  of its  involvement  with a VIE if the  enterprise  has a
significant  variable  interest  in  the  VIE  and to  consolidate  a VIE if the
enterprise is the primary  beneficiary.  VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this  interpretation's  provisions  in the first  interim or
annual  reporting  period  beginning  after June 15, 2003 (our third  quarter of
2003).  The FASB also  identified  transitional  disclosure  provisions  for all
financial statements issued after January 31, 2003.

        The Company  currently has transactions with entities in connection with
the sale of  preferred  securities,  which  may fall  within  the  scope of this
interpretation, and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46. The Company currently consolidates these entities
and believes it will continue to consolidate following the adoption of FIN 46.

9.  SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):

        The  following  summarizes  certain  consolidated  operating  results by
quarter for 2002 and 2001.


<TABLE>

<CAPTION>

                                                 March 31,      June 30,     September 30,      December 31,
Three Months Ended                                 2002           2002            2002             2002
-------------------------------------------------------------------------------------------------------------
                                                                       (In millions)
<S>                                               <C>             <C>            <C>               <C>
Operating Revenues..........................      $450.7          $501.3         $779.9            $596.5
Operating Expenses and Taxes................       389.4           423.1          658.6             522.1
-------------------------------------------------------------------------------------------------------------
Operating Income............................        61.3            78.2          121.3              74.4
Other Income ...............................         2.8             2.2            1.2               1.5
Net Interest Charges........................        24.1            23.0           21.8              22.1
-------------------------------------------------------------------------------------------------------------
Net Income..................................      $ 40.0          $ 57.4         $100.7            $ 53.8
=============================================================================================================
Earnings on Common Stock....................      $ 39.2          $ 57.0         $103.5            $ 53.7
=============================================================================================================


<CAPTION>
                                                          Three Months Ended
                                                 ------------------------------------
                                                 March 31,      June 30,     Sept. 30,   Oct. 1-Nov. 6,  Nov. 7-Dec. 31,
                                                   2001          2001           2001          2001          2001
----------------------------------------------------------------------------------------------------------------------
                                                                            (In millions)
<S>                                               <C>            <C>            <C>          <C>           <C>
Operating Revenues..........................      $461.7         $521.0         $672.2       $ 183.7   |   $282.9
Operating Expenses and Taxes................       388.2          451.7          554.0         151.9   |    239.2
-------------------------------------------------------------------------------------------------------|--------------
Operating Income............................        73.5           69.3          118.2          31.8   |     43.7
Other Income (Expense)......................         1.2            2.3           (2.7)       (177.7)  |      1.2
Net Interest Charges........................        23.3           25.6           24.3           8.3   |     14.8
-------------------------------------------------------------------------------------------------------|--------------
Net Income (Loss)...........................      $ 51.4         $ 46.0         $ 91.2       $(154.2)  |   $ 30.1
=======================================================================================================|==============
Earnings (Loss) on Common Stock.............      $ 50.0         $ 44.7         $ 89.8       $(154.5)  |   $ 29.3
======================================================================================================================

                                                           30

</TABLE>

<PAGE>


Report of Independent Accountants


To the Stockholders and Board of Directors of
Jersey Central Power & Light Company:

In our opinion,  the  accompanying  consolidated  balance sheet and consolidated
statement of capitalization and the related  consolidated  statements of income,
common  stockholder's  equity,  preferred  stock,  cash flows and taxes  present
fairly, in all material respects, the financial position of Jersey Central Power
&  Light  Company  (a  wholly  owned   subsidiary  of  FirstEnergy   Corp.)  and
subsidiaries  as of December 31, 2002,  and the results of their  operations and
their cash flows for the year then ended and the year ended  December  31,  2000
(pre-merger) in conformity with accounting  principles generally accepted in the
United States of America.  These financial  statements are the responsibility of
the Company's  management;  our responsibility is to express an opinion on these
financial  statements  based on our  audit.  We  conducted  our  audits of these
statements  in  accordance  with auditing  standards  generally  accepted in the
United  States of America,  which  require that we plan and perform the audit to
obtain reasonable  assurance about whether the financial  statements are free of
material  misstatement.  An audit includes examining,  on a test basis, evidence
supporting the amounts and  disclosures in the financial  statements,  assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall  financial  statement  presentation.  We believe that our
audits provide a reasonable basis for our opinion.  The  consolidated  financial
statements  of Jersey  Central  Power & Light  Company  and  subsidiaries  as of
December  31, 2001 and for the period  from  January 1, 2001 to November 6, 2001
(pre-merger)  and the  period  from  November  7,  2001  to  December  31,  2001
(post-merger)  were  audited by other  independent  accountants  who have ceased
operations.  Those independent  accountants  expressed an unqualified opinion on
those financials statements in their report dated March 18, 2002.



PricewaterhouseCoopers LLP

Cleveland, Ohio
February 28, 2003

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<PAGE>


The following report is a copy of a report  previously issued by Arthur Andersen
LLP and has not been reissued by Arthur Andersen LLP.


Report of Previous Independent Public Accountants


To the Stockholders and Board of Directors of
Jersey Central Power & Light Company:

We have audited the  accompanying  consolidated  balance sheet and  consolidated
statement  of  capitalization  of Jersey  Central  Power & Light  Company (a New
Jersey  corporation  and  wholly  owned  subsidiary  of  FirstEnergy  Corp.) and
subsidiaries as of December 31, 2001 (post-merger), and the related consolidated
statements of income, common stockholder's  equity,  preferred stock, cash flows
and taxes for the period from  January 1, 2001 to November 6, 2001  (pre-merger)
and the period from November 7, 2001 to December 31, 2001  (post-merger).  These
financial  statements are the  responsibility of the Company's  management.  Our
responsibility  is to express an opinion on these financial  statements based on
our audit. The financial  statements of Jersey Central Power & Light Company and
subsidiary  as of December  31, 2000 and for each of the two years in the period
ended  December  31, 2000  (pre-merger),  were audited by other  auditors  whose
report  dated  January  31,  2001,  expressed  an  unqualified  opinion on those
statements.

We conducted our audit in accordance with auditing standards  generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable  assurance about whether the financial  statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting  the amounts and  disclosures in the financial  statements.  An audit
also includes assessing the accounting principles used and significant estimates
made by  management,  as well as  evaluating  the  overall  financial  statement
presentation.  We believe  that our audit  provides a  reasonable  basis for our
opinion.

In our opinion,  the 2001 financial statements referred to above present fairly,
in all material respects, the financial position of Jersey Central Power & Light
Company and subsidiaries as of December 31, 2001 (post-merger),  and the results
of their  operations and their cash flows for the period from January 1, 2001 to
November 6, 2001  (pre-merger)  and the period from November 7, 2001 to December
31, 2001  (post-merger),  in conformity  with  accounting  principles  generally
accepted in the United States.



ARTHUR ANDERSEN LLP

Cleveland, Ohio,
   March 18, 2002.

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